Filed by Bowne Pure Compliance

SUBURBAN PROPANE PARTNERS, L.P.

Date: November 26, 2008

/s/ MARK A. ALEXANDER

Mark A. Alexander

Chief Executive Officer and Supervisor

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

þ Annual Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934

For the fiscal year ended September 27, 2008

o Transition Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934

Commission File Number: 1-14222

SUBURBAN PROPANE PARTNERS, L.P.

(Exact name of registrant as specified in its charter)


Delaware		22-3410353
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

240 Route 10 West
Whippany, NJ 07981
(973) 887-5300
(Address, including zip code, and telephone number,
including area code, of registrant’s principal executive offices)

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 þ No o

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 o No þ

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 þ No o

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. þ

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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
		(do not check if a smaller reporting company)

Indicate by check mark whether registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes o No þ

The aggregate market value as of March 28, 2008 of the registrant’s Common Units held by non-affiliates of the registrant, based on the reported closing price of such units on the New York Stock Exchange on such date ($37.88 per unit), was approximately $1,239,638,000.


Documents Incorporated by Reference: None		Total number of pages (excluding Exhibits): 134

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K contains forward-looking statements (“Forward-Looking Statements”) as defined in the Private Securities Litigation Reform Act of 1995 and Section 27A of the Securities Act of 1933, as amended, relating to future business expectations and predictions and financial condition and results of operations of Suburban Propane Partners, L.P. (the “Partnership”). Some of these statements can be identified by the use of forward-looking terminology such as “prospects,” “outlook,” “believes,” “estimates,” “intends,” “may,” “will,” “should,” “anticipates,” “expects” or “plans” or the negative or other variation of these or similar words, or by discussion of trends and conditions, strategies or risks and uncertainties. These Forward-Looking Statements involve certain risks and uncertainties that could cause actual results to differ materially from those discussed or implied in such Forward-Looking Statements (statements contained in this Annual Report identifying such risks and uncertainties are referred to as “Cautionary Statements”). The risks and uncertainties and their impact on the Partnership’s results include, but are not limited to, the following risks:

•		The impact of weather conditions on the demand for propane, fuel oil and other refined fuels, natural gas and electricity;

•		Volatility in the unit cost of propane, fuel oil and other refined fuels and natural gas, the impact of the Partnership’s hedging and risk management activities, and the adverse impact of price increases on volumes as a result of customer conservation;

•		The ability of the Partnership to compete with other suppliers of propane, fuel oil and other energy sources;

•		The impact on the price and supply of propane, fuel oil and other refined fuels from the political, military or economic instability of the oil producing nations, global terrorism and other general economic conditions;

•		The ability of the Partnership to acquire and maintain reliable transportation for its propane, fuel oil and other refined fuels;

•		The ability of the Partnership to retain customers;

•		The impact of customer conservation, energy efficiency and technology advances on the demand for propane and fuel oil;

•		The ability of management to continue to control expenses;

•		The impact of changes in applicable statutes and government regulations, or their interpretations, including those relating to the environment and global warming and other regulatory developments on the Partnership’s business;

•		The impact of legal proceedings on the Partnership’s business;

•		The impact of operating hazards that could adversely affect the Partnership’s operating results to the extent not covered by insurance;

•		The Partnership’s ability to make strategic acquisitions and successfully integrate them; and

•		The impact of current conditions in the global capital and credit markets, and general economic pressures.

Some of these Forward-Looking Statements are discussed in more detail in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this Annual Report. On different occasions, the Partnership or its representatives have made or may make Forward-Looking Statements in other filings with the Securities and Exchange Commission (“SEC”), press releases or oral statements made by or with the approval of one of the Partnership’s authorized executive officers. Readers are cautioned not to place undue reliance on Forward-Looking Statements, which reflect management’s view only as of the date made. The Partnership undertakes no obligation to update any Forward-Looking Statement or Cautionary Statement, except as required by law. 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 in this Annual Report and in future SEC reports. For a more complete discussion of specific factors which could cause actual results to differ from those in the Forward-Looking Statements or Cautionary Statements, see ‘‘Risk Factors’’ in this Annual Report.

PART I

ITEM 1. BUSINESS

Development of Business

Suburban Propane Partners, L.P. (the “Partnership”), a publicly traded Delaware limited partnership, is a nationwide marketer and distributor of a diverse array of products meeting the energy needs of our customers. We specialize in the distribution of propane, fuel oil and refined fuels, as well as the marketing of natural gas and electricity in deregulated markets. In support of our core marketing and distribution operations, we install and service a variety of home comfort equipment, particularly in the areas of heating and ventilation. We believe, based on LP/Gas Magazine dated February 2008, that we are the fourth largest retail marketer of propane in the United States, measured by retail gallons sold in the year 2007. As of September 27, 2008, we were serving the energy needs of more than 900,000 active residential, commercial, industrial and agricultural customers through approximately 300 locations in 30 states located primarily in the east and west coast regions of the United States, including Alaska. We sold approximately 386.2 million gallons of propane to retail customers and 76.5 million gallons of fuel oil and refined fuels during the year ended September 27, 2008. Together with our predecessor companies, we have been continuously engaged in the retail propane business since 1928.

We conduct our business principally through Suburban Propane, L.P., a Delaware limited partnership, which operates our propane business and assets (the “Operating Partnership”), and its direct and indirect subsidiaries. Our general partner, and the general partner of our Operating Partnership, is Suburban Energy Services Group LLC (the “General Partner”), a Delaware limited liability company. Since October 19, 2006, the General Partner has had no economic interest in either the Partnership or the Operating Partnership other than as a holder of 784 Common Units of the Partnership. Prior to October 19, 2006, the General Partner was majority-owned by senior management of the Partnership and owned an approximate combined 1.75% general partner interest in the Partnership and the Operating Partnership.

On October 19, 2006, the Partnership, the Operating Partnership and the General Partner consummated an Exchange Agreement by and among the parties dated July 27, 2006 (the “Exchange Agreement”), pursuant to which the Partnership issued 2,300,000 Common Units to the General Partner in exchange for the cancellation of the General Partner’s incentive distribution rights (“IDRs”), the economic interest in the Partnership included in the general partner interest therein and the economic interest in the Operating Partnership included in the general partner interest therein (the “GP Exchange Transaction”). Pursuant to a Distribution, Release and Lockup Agreement dated July 27, 2006 by and among the Partnership, the Operating Partnership, the General Partner and the then individual members of the General Partner (the “Distribution Agreement”), the Common Units received by the General Partner (other than 784 Common Units that will remain in the General Partner) were distributed to the then members of the General Partner in exchange for their interests in the General Partner.

In addition to the GP Exchange Transaction, the Partnership adopted the Third Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”), which amended the Previous Partnership Agreement to, among other things, effectuate the GP Exchange Transaction. Under the Partnership Agreement, the General Partner will continue to be the general partner of both the Partnership and the Operating Partnership, but its general partner interests will have no economic value (which means that such general partner interests do not entitle the holder thereof to any cash distributions of either partnership, or to any cash payment upon the liquidation of either partnership, or any other economic rights in either partnership). Following the GP Exchange Transaction and the consummation of the Distribution Agreement, the sole member of the General Partner is the Chief Executive Officer of the Partnership and the General Partner holds 784 Common Units received in the GP Exchange Transaction. The Partnership continues to own all of the limited partner interests in the Operating Partnership, with 0.1% thereof held through a limited liability company, wholly-owned (directly and indirectly) by the Partnership. Additionally, under the Partnership Agreement no incentive distribution rights are outstanding and no provisions for future incentive distribution rights are contained in the Partnership Agreement. The Common Units represent 100% of the limited partner interests in the Partnership.

Subsidiaries of the Operating Partnership include Suburban Sales and Service, Inc. (the “Service Company”), which conducts a portion of the Partnership’s service work and appliance and parts businesses. The Service Company is the sole member of Gas Connection, LLC (d/b/a HomeTown Hearth & Grill), and Suburban Franchising, LLC. HomeTown Hearth & Grill sells and installs natural gas and propane gas grills, fireplaces and related accessories and supplies through four retail stores in the northwest and northeast regions as of September 27, 2008. Suburban Franchising creates and develops propane related franchising business opportunities.

On December 23, 2003, we acquired substantially all of the assets and operations of Agway Energy Products, LLC, Agway Energy Services, Inc. and Agway Energy Services PA, Inc. (collectively referred to as “Agway Energy”) pursuant to an asset purchase agreement dated November 10, 2003 (the “Agway Acquisition”). With the Agway Acquisition, we transformed our business from a marketer of a single fuel into one that provides multiple energy solutions, with expansion into the marketing and distribution of fuel oil and refined fuels, as well as the marketing of natural gas and electricity. Our fuel oil and refined fuels, natural gas and electricity and services businesses are structured as corporate entities (collectively referred to as Corporate Entities) and, as such, are subject to corporate level income tax.

Suburban Energy Finance Corporation, a direct wholly-owned subsidiary of the Partnership, was formed on November 26, 2003 to serve as co-issuer, jointly and severally with the Partnership, of the Partnership’s unsecured 6.875% senior notes due December 2013. Suburban Energy Finance Corporation has nominal assets and conducts no business operations.

In this Annual Report, unless otherwise indicated, the terms “Partnership,” “we,” “us,” and “our” are used to refer to Suburban Propane Partners, L.P. or to Suburban Propane Partners, L.P. and its consolidated subsidiaries, including the Operating Partnership. The Partnership, the Operating Partnership and the Service Company commenced operations in March 1996 in connection with the Partnership’s initial public offering of Common Units.

We currently file Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and current reports on Form 8-K with the SEC. You may read and receive copies of any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Any information filed by us is also available on the SEC’s EDGAR database at www.sec.gov.

Upon written request or through a link from our website at www.suburbanpropane.com, we will provide, without charge, copies of our Annual Report on Form 10-K for the year ended September 27, 2008, each of the Quarterly Reports on Form 10-Q, current reports filed or furnished on Form 8-K and all amendments to such reports as soon as is reasonably practicable after such reports are electronically filed with or furnished to the SEC. Requests should be directed to: Suburban Propane Partners, L.P., Investor Relations, P.O. Box 206, Whippany, New Jersey 07981-0206.

Our Strategy

Our business strategy is to deliver increasing value to our Unitholders through initiatives, both internal and external, that are geared toward achieving sustainable profitable growth and increased quarterly distributions. The following are key elements of our strategy:

Internal Focus on Driving Operating Efficiencies, Right-Sizing Our Cost Structure and Enhancing Our Customer Mix. We focus internally on improving the efficiency of our existing operations, managing our cost structure and improving our customer mix. Through investments in our technology infrastructure, we continue to seek to improve operating efficiencies and the return on assets employed. Beginning at the end of fiscal 2005 and continuing throughout much of fiscal 2007, we implemented specific plans to streamline our operating footprint and management structure, eliminate redundant functions and assets through enhanced operating efficiencies, and refocus our service activities on offerings to support our existing customer base within our core operating segments. While the majority of the specific initiatives under these plans were executed by the end of fiscal 2007, our focus on operating efficiencies and on our cost structure is an ongoing process. Our internal efforts are particularly focused in the areas of route optimization, forecasting customer usage, inventory control, cash management and customer tracking.

In addition, we continually evaluate our customer base and, in particular, focus on customers that provide a proper return. In that regard, our efforts to strategically exit certain lower margin business in both our propane and fuel oil and refined fuels segments has resulted in a reduction in volumes sold, yet has had a favorable impact on overall segment profitability.

Growing Our Customer Base by Improving Customer Retention and Acquiring New Customers. We set clear objectives to focus our employees on seeking new customers and retaining existing customers by providing world-class customer service. We believe that customer satisfaction is a critical factor in the growth and success of our operations. “Our Business is Customer Satisfaction” is one of our core operating philosophies. We measure and reward our customer service centers based on a combination of profitability of the individual customer service center and net customer growth.

Selective Acquisitions of Complementary Businesses or Assets. Externally, we seek to extend our presence or diversify our product offerings through selective acquisitions. Our acquisition strategy is to focus on businesses with a relatively steady cash flow that will extend our presence in strategically attractive markets, complement our existing business segments or provide an opportunity to diversify our operations with other energy-related assets. While we are active in this area, we are also very patient and deliberate in evaluating acquisition candidates. There were no acquisitions completed during fiscal 2008, 2007 or 2006 as we focused internally on driving efficiencies, reducing costs and integrating the operations of Agway Energy which were acquired in fiscal 2004. However, during fiscal 2007 we completed a non-cash transaction in which we disposed of nine customer service centers considered to be in markets that were non-strategic to our operations in exchange for three customer service centers located in Alaska, thus expanding our presence in this strategically attractive market.

Selective Disposition of Non-Strategic Assets. We continuously evaluate our existing facilities to identify opportunities to optimize our return on assets by selectively divesting operations in slower growing markets, generating proceeds that can be reinvested in markets that present greater opportunities for growth. Our objective is to fully exploit the growth and profit potential of all of our assets. In that regard, on October 2, 2007 we completed the sale of our Tirzah, South Carolina underground granite propane storage cavern, and associated 62-mile pipeline, for approximately $53.7 million in net proceeds which have been reinvested in the business.

Business Segments

We manage and evaluate our operations in six segments, four of which are reportable segments: Propane, Fuel Oil and Refined Fuels, Natural Gas and Electricity and Services. These business segments are described below. See the Notes to the Consolidated Financial Statements included in this Annual Report for financial information about our business segments.

Propane

Propane is a by-product of natural gas processing and petroleum refining. It is a clean burning energy source recognized for its transportability and ease of use relative to alternative forms of stand-alone energy sources. Propane use falls into three broad categories:

	•		residential and commercial applications;

	•		industrial applications; and

	•		agricultural uses.

In the residential and commercial markets, propane is used primarily for space heating, water heating, clothes drying and cooking. Industrial customers use propane generally as a motor fuel to power over-the-road vehicles, forklifts and stationary engines, to fire furnaces, as a cutting gas and in other process applications. In the agricultural market, propane is primarily used for tobacco curing, crop drying, poultry brooding and weed control.

Propane is extracted from natural gas or oil wellhead gas at processing plants or separated from crude oil during the refining process. It is normally transported and stored in a liquid state under moderate pressure or refrigeration for ease of handling in shipping and distribution. When the pressure is released or the temperature is increased, propane becomes a flammable gas that is colorless and odorless, although an odorant is added to allow its detection. Propane is clean burning and, when consumed, produces only negligible amounts of pollutants.

Product Distribution and Marketing

We distribute propane through a nationwide retail distribution network consisting of approximately 300 locations in 30 states as of September 27, 2008. Our operations are concentrated in the east and west coast regions of the United States, including Alaska. In fiscal 2008, we serviced approximately 745,000 active propane customers. Typically, our customer service centers are located in suburban and rural areas where natural gas is not readily available. Generally, these customer service centers consist of an office, appliance showroom, warehouse and service facilities, with one or more 18,000 to 30,000 gallon storage tanks on the premises. Most of our residential customers receive their propane supply through an automatic delivery system that eliminates the customer’s need to make an affirmative purchase decision. These deliveries are scheduled through computer technology, based upon each customer’s historical consumption patterns and prevailing weather conditions. Additionally, as is common practice in the industry, we offer our customers a budget payment plan whereby the customer’s estimated annual propane purchases and service contracts are paid for in a series of estimated equal monthly payments over a twelve-month period. From our customer service centers, we also sell, install and service equipment to customers who purchase propane from us including heating and cooking appliances, hearth products and supplies and, at some locations, propane fuel systems for motor vehicles.

We sell propane primarily to six customer markets: residential, commercial, industrial (including engine fuel), agricultural, other retail users and wholesale. Approximately 95% of the propane gallons sold by us in fiscal 2008 were to retail customers: 43% to residential customers, 32% to commercial customers, 9% to industrial customers, 6% to agricultural customers and 10% to other retail users. The balance of approximately 5% of the propane gallons sold by us in fiscal 2008 was for risk management activities and wholesale customers. Sales to residential customers in fiscal 2008 accounted for approximately 63% of our margins on retail propane sales, reflecting the higher-margin nature of the residential market. No single customer accounted for 10% or more of our propane revenues during fiscal 2008.

Retail deliveries of propane are usually made to customers by means of bobtail and rack trucks. Propane is pumped from bobtail trucks, which have capacities ranging from 2,125 gallons to 2,975 gallons of propane, into a stationary storage tank on the customers’ premises. The capacity of these storage tanks ranges from approximately 100 gallons to approximately 1,200 gallons, with a typical tank having a capacity of 300 to 400 gallons. As is common in the propane industry, we own a significant portion of the storage tanks located on our customers’ premises. We also deliver propane to retail customers in portable cylinders, which typically have a capacity of 5 to 35 gallons. When these cylinders are delivered to customers, empty cylinders are refilled in place or transported for replenishment at our distribution locations. We also deliver propane to certain other bulk end users in larger trucks known as transports, which have an average capacity of approximately 9,000 gallons. End users receiving transport deliveries include industrial customers, large-scale heating accounts, such as local gas utilities that use propane as a supplemental fuel to meet peak load delivery requirements, and large agricultural accounts that use propane for crop drying.

In our wholesale operations, we principally sell propane to large industrial end users and other propane distributors. The wholesale market includes customers who use propane to fire furnaces, as a cutting gas and in other process applications. Due to the low margin nature of the wholesale market as compared to the retail market, we have reduced our emphasis on wholesale marketing over the last several years.

Supply

Our propane supply is purchased from approximately 55 oil companies and natural gas processors at approximately 115 supply points located in the United States and Canada. We make purchases primarily under one-year agreements that are subject to annual renewal, and also purchase propane on the spot market. Supply contracts generally provide for pricing in accordance with posted prices at the time of delivery or the current prices established at major storage points, and some contracts include a pricing formula that typically is based on prevailing market prices. Some of these agreements provide maximum and minimum seasonal purchase guidelines. Propane is generally transported from refineries, pipeline terminals, storage facilities (including our storage facility in Elk Grove, California) and coastal terminals to our customer service centers by a combination of common carriers, owner-operators and railroad tank cars. See Item 2 of this Annual Report.

Historically, supplies of propane have been readily available from our supply sources. Although we make no assurance regarding the availability of supplies of propane in the future, we currently expect to be able to secure adequate supplies during fiscal 2009. During fiscal 2008, Targa Liquids Marketing and Trade (“Targa”) provided approximately 19% of our total propane purchases. Aside from this supplier, no single supplier provided more than 10% of our total propane supply during fiscal 2008. The availability of our propane supply is dependent on several factors, including the severity of winter weather and the price and availability of competing fuels, such as natural gas and fuel oil. We believe that if supplies from Targa were interrupted, we would be able to secure adequate propane supplies from other sources without a material disruption of our operations. Nevertheless, the cost of acquiring such propane might be higher and, at least on a short-term basis, margins could be affected. Approximately 95% of our total propane purchases were from domestic suppliers in fiscal 2008.

We seek to reduce the effect of propane price volatility on our product costs and to help ensure the availability of propane during periods of short supply. We are currently a party to propane futures transactions on the New York Mercantile Exchange (“NYMEX”) and to forward and option contracts with various third parties to purchase and sell product at fixed prices in the future. These activities are monitored by our senior management through enforcement of our Hedging and Risk Management Policy. See Items 7 and 7A of this Annual Report.

We own and operate a large propane storage facility in California. We also operate smaller storage facilities in other locations and have rights to use storage facilities in additional locations (including our former facility in Tirzah, South Carolina). These storage facilities enable us to buy and store large quantities of propane particularly during periods of low demand, which generally occur during the summer months. This practice helps ensure a more secure supply of propane during periods of intense demand or price instability. As of September 27, 2008, the majority of our storage capacity in California was leased to third parties. On October 2, 2007, we completed the sale of our Tirzah, South Carolina underground granite propane storage cavern, and associated 62-mile pipeline.

Competition

According to the Energy Information Administration, propane accounts for approximately 4% of household energy consumption in the United States. This level has not changed materially over the previous two decades. As an energy source, propane competes primarily with natural gas, electricity and fuel oil, principally on the basis of price, availability and portability.

Propane is more expensive than natural gas on an equivalent British Thermal Unit basis in locations serviced by natural gas, but it is an alternative to natural gas in rural and suburban areas where natural gas is unavailable or portability of product is required. Historically, the expansion of natural gas into traditional propane markets has been inhibited by the capital costs required to expand pipeline and retail distribution systems. Although the recent extension of natural gas pipelines to previously unserved geographic areas tends to displace propane distribution in those areas, we believe new opportunities for propane sales have been arising as new neighborhoods are developed in geographically remote areas.

We also have some relative advantages over suppliers of other energy sources. For example, propane is generally less expensive to use than electricity for space heating, water heating, clothes drying and cooking. Fuel oil has not been a significant competitor due to the current geographical diversity of our operations, and propane and fuel oil are not significant competitors because of the cost of converting from one to the other.

In addition to competing with suppliers of other energy sources, our propane operations compete with other retail propane distributors. The retail propane industry is highly fragmented and competition generally occurs on a local basis with other large full-service multi-state propane marketers, thousands of smaller local independent marketers and farm cooperatives. Based on industry statistics contained in 2006 Sales of Natural Gas Liquids and Liquefied Refinery Gases, as published by the American Petroleum Institute in December 2007, and LP/Gas Magazine dated February 2008, the ten largest retailers, including us, account for approximately 43% of the total retail sales of propane in the United States. During fiscal year 2008, one marketer had more than a 10% share of the total retail propane market in the United States. For fiscal years 2007 and 2006, no single marketer had a greater than 10% share of the total retail propane market in the United States. Most of our customer service centers compete with five or more marketers or distributors. However, each of our customer service centers operates in its own competitive environment because retail marketers tend to locate in close proximity to customers in order to lower the cost of providing service. Our typical customer service center has an effective marketing radius of approximately 50 miles, although in certain rural areas the marketing radius may be extended by a satellite office.

Fuel Oil and Refined Fuels

Product Distribution and Marketing

We market and distribute fuel oil, kerosene, diesel fuel and gasoline to approximately 90,000 residential and commercial customers in the northeast region of the United States. Sales of fuel oil and refined fuels for fiscal 2008 amounted to 76.5 million gallons. Approximately 65% of the fuel oil and refined fuels gallons sold by us in fiscal 2008 were to residential customers, principally for home heating, 4% were to commercial customers, 1% were to agricultural and 4% to other users. Fuel oil has a more limited use, compared to propane, for space and water heating in residential and commercial buildings. We sell diesel fuel and gasoline to commercial and industrial customers for use primarily to propel motor vehicles. Due to the low margin nature of the diesel fuel and gasoline businesses, at the end of fiscal 2005 we made a decision to reduce our emphasis on these activities and, in certain instances, exited the business. Sales of diesel and gasoline accounted for the remaining 26% of total volumes sold in this segment during fiscal 2008.

Approximately 61% of our fuel oil customers receive their fuel oil under an automatic delivery system without the customer having to make an affirmative purchase decision. These deliveries are scheduled through computer technology, based upon each customer’s historical consumption patterns and prevailing weather conditions. Additionally, as is common practice in the industry, we offer our customers a budget payment plan whereby the customer’s estimated annual fuel oil purchases and service contracts are paid for in a series of estimated equal monthly payments over a twelve-month period. From our customer service centers, we also sell, install and service equipment to customers who purchase fuel oil from us including heating appliances.

Deliveries of fuel oil are usually made to customers by means of tankwagon trucks, which have capacities ranging from 2,500 gallons to 3,000 gallons. Fuel oil is pumped from the tankwagon truck into a stationary storage tank that is located on the customer’s premises, which is owned by the customer. The capacity of customer storage tanks ranges from approximately 275 gallons to approximately 1,000 gallons. No single customer accounted for 10% or more of our fuel oil revenues during fiscal 2008.

Supply

We obtain fuel oil and other refined fuels in either pipeline, truckload or tankwagon quantities, and have contracts with certain pipeline and terminal operators for the right to temporarily store fuel oil at more than 13 terminal facilities we do not own. We have arrangements with certain suppliers of fuel oil, which provide open access to fuel oil at specific terminals throughout the northeast. Additionally, a portion of our purchases of fuel oil are made at local wholesale terminal racks. In most cases, the supply contracts do not establish the price of fuel oil in advance; rather, prices are typically established based upon market prices at the time of delivery plus or minus a differential for transportation and volume discounts. We purchase fuel oil from more than 20 suppliers at approximately 60 supply points. While fuel oil supply is more susceptible to longer periods of supply constraint than propane, we believe that our supply arrangements will provide us with sufficient supply sources. Although we make no assurance regarding the availability of supplies of fuel oil in the future, we currently expect to be able to secure adequate supplies during fiscal 2009.

Competition

The fuel oil industry is a mature industry with total demand expected to remain relatively flat to moderately declining. The fuel oil industry is highly fragmented, characterized by a large number of relatively small, independently owned and operated local distributors. We compete with other fuel oil distributors offering a broad range of services and prices, from full service distributors to those that solely offer the delivery service. We have developed a wide range of sales programs and service offerings for our fuel oil customer base in an attempt to be viewed as a full service energy provider and to build customer loyalty. For instance, like most companies in the fuel oil business, we provide home heating equipment repair service to our fuel oil customers through our services segment on a 24-hour a day basis. The fuel oil business unit also competes for retail customers with suppliers of alternative energy sources, principally natural gas, propane and electricity.

Natural Gas and Electricity

We market natural gas and electricity through our wholly-owned subsidiary Agway Energy Services, LLC (“AES”) in the deregulated markets of New York and Pennsylvania primarily to residential and small commercial customers. Historically, local utility companies provided their customers with all three aspects of electric and natural gas service: generation, transmission and distribution. However, under deregulation, public utility commissions in several states are licensing energy service companies, such as AES, to act as alternative suppliers of the commodity to end consumers. In essence, we make arrangements for the supply of electricity or natural gas to specific delivery points. The local utility companies continue to distribute electricity and natural gas on their distribution systems. The business strategy of this business segment is to expand its market share by concentrating on growth in the customer base and expansion into other deregulated markets that are considered strategic markets.

We serve nearly 71,000 natural gas and electricity customers in New York and Pennsylvania. During fiscal 2008, we sold approximately 4.1 million dekatherms of natural gas and 493.1 million kilowatt hours of electricity through the natural gas and electricity segment. Approximately 80% of our customers were residential households and the remainder was small commercial and industrial customers. New accounts are obtained through numerous marketing and advertising programs, including telemarketing and direct mail initiatives. Most local utility companies have established billing service arrangements whereby customers receive a single bill from the local utility company which includes distribution charges from the local utility company, as well as product charges for the amount of natural gas or electricity provided by AES and utilized by the customer. We have arrangements with several local utility companies that provide billing and collection services for a fee. Under these arrangements, we are paid by the local utility company for all or a portion of customer billings after a specified number of days following the customer billing with no further recourse to AES.

Supply of natural gas is arranged through annual supply agreements with major national wholesale suppliers. Pricing under the annual natural gas supply contracts is based on posted market prices at the time of delivery, and some contracts include a pricing formula that typically is based on prevailing market prices. The majority of our electricity requirements are purchased through the New York Independent System Operator (“NYISO”) under an annual supply agreement, as well as purchase arrangements through other national wholesale suppliers on the open market. Electricity pricing under the NYISO agreement is based on local market indices at the time of delivery. Competition is primarily with local utility companies, as well as other marketers of natural gas and electricity providing similar alternatives as AES.

Services

We sell, install and service all types of whole-house heating products, air cleaners, humidifiers, de-humidifiers, hearth products and space heaters to the customers of our propane, fuel oil, natural gas and electricity products. We also offer services such as duct cleaning, air balancing and energy audits to those customers. Our supply needs are filled through supply arrangements with several large regional equipment manufacturers and distribution companies. Competition in this business segment is primarily with small, local heating and ventilation providers and contractors, as well as, to a lesser extent, other regional service providers. During the third quarter of fiscal 2006, we initiated plans to restructure our service offerings and eliminated certain stand-alone installation activities. See the Notes to the consolidated financial statements in this Annual Report. The focus of our ongoing service offerings are in support of the service needs of our existing customer base within our propane, refined fuels and natural gas and electricity business segments. Additionally, we have entered into arrangements with third-party service providers to complement and, in certain instances, supplement our existing service capabilities.

All Other

Activities from our HomeTown Hearth & Grill and Suburban Franchising subsidiaries comprise the all other business caption.

Seasonality

The retail propane and fuel oil distribution businesses, as well as the natural gas marketing business, are seasonal because the primary use of these fuels is for heating residential and commercial buildings. Historically, approximately two-thirds of our retail propane volume is sold during the six-month peak heating season from October through March. The fuel oil business tends to experience greater seasonality given its more limited use for space heating and approximately three-fourths of our fuel oil volumes are sold between October and March. Consequently, sales and operating profits are concentrated in our first and second fiscal quarters. Cash flows from operations, therefore, are greatest during the second and third fiscal quarters when customers pay for product purchased during the winter heating season. We expect lower operating profits and either net losses or lower net income during the period from April through September (our third and fourth fiscal quarters).

Weather conditions have a significant impact on the demand for our products, in particular propane, fuel oil and natural gas, for both heating and agricultural purposes. Many of our customers rely heavily on propane, fuel oil or natural gas as a heating source. Accordingly, the volume sold is directly affected by the severity of the winter weather in our service areas, which can vary substantially from year to year. In any given area, sustained warmer than normal temperatures will tend to result in reduced propane, fuel oil and natural gas consumption, while sustained colder than normal temperatures will tend to result in greater consumption.

Trademarks and Tradenames

We utilize a variety of trademarks and tradenames owned by us, including “Suburban Propane,” “Gas Connection” and “HomeTown Hearth & Grill.” Additionally, in connection with the Agway Acquisition, we acquired rights to certain trademarks and tradenames, including “Agway Propane,” “Agway” and “Agway Energy Products” in connection with the distribution of petroleum-based fuel and sales and service of heating and ventilation. We regard our trademarks, tradenames and other proprietary rights as valuable assets and believe that they have significant value in the marketing of our products and services.

Government Regulation; Environmental and Safety Matters

We are subject to various federal, state and local environmental, health and safety laws and regulations. Generally, these laws impose limitations on the discharge of pollutants and establish standards for the handling of solid and hazardous wastes and can require the investigation and cleanup of environmental contamination. 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 liability 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. Propane is not a hazardous substance within the meaning of CERCLA, whereas fuel oil is considered a hazardous substance. We own real property at locations where such hazardous substances may be present as a result of prior activities.

We expect that we will be required to expend funds to participate in the remediation of certain sites, including sites where we have been designated by the Environmental Protection Agency as a potentially responsible party under CERCLA and at sites with aboveground and underground fuel storage tanks. We will also incur other expenses associated with environmental compliance. We continually monitor our operations with respect to potential environmental issues, including changes in legal requirements and remediation technologies.

With the Agway Acquisition, we acquired certain surplus properties with either known or probable environmental exposure, some of which are currently in varying stages of investigation, remediation or monitoring. Additionally, we identified that certain active sites acquired contained environmental conditions which required further investigation, future remediation or ongoing monitoring activities. The environmental exposures included instances of soil and/or groundwater contamination associated with the handling and storage of fuel oil, gasoline and diesel fuel.

As of September 27, 2008, we had accrued environmental liabilities of $1.6 million representing the total estimated future liability for remediation and monitoring.

Estimating the extent of our responsibility at a particular site, and the method and ultimate cost of remediation of that site, requires making numerous assumptions. As a result, the ultimate cost to remediate any site may differ from current estimates, and will depend, in part, on whether there is additional contamination, not currently known to us, at that site. However, we believe that our past experience provides a reasonable basis for estimating these liabilities. As additional information becomes available, estimates are adjusted as necessary. While we do not anticipate that any such adjustment would be material to our financial statements, the result of ongoing or future environmental studies or other factors could alter this expectation and require recording additional liabilities. We currently cannot determine whether we will incur additional liabilities or the extent or amount of any such liabilities.

National Fire Protection Association (“NFPA”) Pamphlet Nos. 54 and 58, which establish rules and procedures governing the safe handling of propane, or comparable regulations, have been adopted, in whole, in part or with state addenda, as the industry standard for propane storage, distribution and equipment installation and operation in all of the states in which we operate. In some states these laws are administered by state agencies, and in others they are administered on a municipal level. Pamphlet No. 58 has adopted storage tank valve retrofit requirements due to be completed by June 2011 or later depending on when each state adopts the 2001 edition of NFPA Pamphlet No. 58. We have a program in place to meet this deadline.

NFPA Pamphlet Nos. 30, 30A, 31, 385 and 395, which establish rules and procedures governing the safe handling of distillates (fuel oil, kerosene and diesel fuel) and gasoline, or comparable regulations, have been adopted, in whole, in part or with state addenda, as the industry standard for fuel oil, kerosene, diesel fuel and gasoline storage, distribution and equipment installation/operation in all of the states in which we sell those products. In some states these laws are administered by state agencies and in others they are administered on a municipal level.

With respect to the transportation of propane, distillates and gasoline by truck, we are subject to regulations promulgated under the Federal Motor Carrier Safety Act. These regulations cover the transportation of hazardous materials and are administered by the United States Department of Transportation or similar state agencies. We conduct ongoing training programs to help ensure that our operations are in compliance with applicable safety regulations. We maintain various permits that are necessary to operate some of our facilities, some of which may be material to our operations. We believe that the procedures currently in effect at all of our facilities for the handling, storage and distribution of propane, distillates and gasoline are consistent with industry standards and are in compliance, in all material respects, with applicable laws and regulations.

The Department of Homeland Security (“DHS”) has published regulations under 6 CFR Part 27 Chemical Facility Anti-Terrorism Standards. Our facilities are registered with the DHS – we have 468 facilities determined to be “Not a High Risk Chemical Facility” and 16 facilities determined to be Tier 4 (lowest level of security risk). These 16 facilities are currently being reviewed for Security Vulnerability Assessment submission, which is due by December 30, 2008. Because our facilities are currently operating under the security programs developed under guidelines issued by the Department of Transportation, Department of Labor and Environmental Protection Agency, we do not anticipate that we will incur significant costs in order to comply with these DHS regulations.

Future developments, such as stricter environmental, health or safety laws and regulations thereunder, could affect our operations. We do not anticipate that the cost of our compliance with environmental, health and safety laws and regulations, including CERCLA, as currently in effect and applicable to known sites will have a material adverse effect on our financial condition or results of operations. To the extent we discover any environmental liabilities presently unknown to us or environmental, health or safety laws or regulations are made more stringent, however, there can be no assurance that our financial condition or results of operations will not be materially and adversely affected.

Employees

As of September 27, 2008, we had 2,985 full time employees, of whom 430 were engaged in general and administrative activities (including fleet maintenance), 45 were engaged in transportation and product supply activities and 2,510 were customer service center employees. As of September 27, 2008, 96 of our employees were represented by 8 different local chapters of labor unions. We believe that our relations with both our union and non-union employees are satisfactory. From time to time, we hire temporary workers to meet peak seasonal demands.

ITEM 1A. RISK FACTORS

You should carefully consider the specific risk factors set forth below as well as the other information contained or incorporated by reference in this Annual Report. Some factors in this section are Forward-Looking Statements. See ‘‘Disclosure Regarding Forward-Looking Statements’’ above.

Risks Inherent in the Ownership of Our Common Units

Cash distributions are not guaranteed and may fluctuate with our performance and other external factors.

Cash distributions on our Common Units are not guaranteed, and depend primarily on our cash flow and our cash on hand. Because they are not dependent on profitability, which is affected by non-cash items, our cash distributions might be made during periods when we record losses and might not be made during periods when we record profits.

The amount of cash we generate may fluctuate based on our performance and other factors, including:

	•		the impact of the risks inherent in our business operations, as described below;

	•		required principal and interest payments on our debt and restrictions contained in our debt instruments;

	•		issuances of debt and equity securities;

	•		our ability to control expenses;

	•		fluctuations in working capital;

	•		capital expenditures; and

	•		financial, business and other factors, a number of which will be beyond our control.

Our Partnership Agreement gives our Board of Supervisors broad discretion in establishing cash reserves for, among other things, the proper conduct of our business. These cash reserves will affect the amount of cash available for distributions.

We have substantial indebtedness. Our debt agreements may limit our ability to make distributions to Unitholders, as well as our financial flexibility.

As of September 27, 2008, we had total outstanding borrowings of $535.0 million, including $425.0 million of senior notes issued by the Partnership and our wholly-owned subsidiary, Suburban Energy Finance Corporation, and $110.0 million of borrowings outstanding under the Operating Partnership’s term loan. The payment of principal and interest on our debt will reduce the cash available to make distributions on our Common Units. In addition, we will not be able to make any distributions to our Unitholders if there is, or after giving effect to such distribution, there would be, an event of default under the indenture governing the senior notes. The amount of distributions that the Partnership makes to its Unitholders is limited by the senior notes, and the amount of distributions that the Operating Partnership may make to the Partnership is limited by the revolving credit facility. The amount and terms of our debt may also adversely affect our ability to finance future operations and capital needs, limit our ability to pursue acquisitions and other business opportunities and make our results of operations more susceptible to adverse economic and industry conditions. In addition to our outstanding indebtedness, we may in the future require additional debt to finance acquisitions or for general business purposes; however, credit market conditions may impact our ability to access such financing. If we are unable to access needed financing or to generate sufficient cash from operations, we may be required to abandon certain projects or curtail capital expenditures. Additional debt, where it is available, could result in an increase in our leverage. Our ability to make principal and interest payments depends on our future performance, which is subject to many factors, some of which are beyond our control.

Unitholders have limited voting rights.

A Board of Supervisors manages our operations. Our Unitholders have only limited voting rights on matters affecting our business, including the right to elect the members of our Board of Supervisors every three years.

It may be difficult for a third party to acquire us, even if doing so would be beneficial to our Unitholders.

Some provisions of our Partnership Agreement may discourage, delay or prevent third parties from acquiring us, even if doing so would be beneficial to our Unitholders. For example, our Partnership Agreement contains a provision, based on Section 203 of the Delaware General Corporation Law, that generally prohibits the Partnership from engaging in a business combination with a 15% or greater Unitholder for a period of three years following the date that person or entity acquired at least 15% of our outstanding Common Units, unless certain exceptions apply. Additionally, our Partnership Agreement sets forth advance notice procedures for a Unitholder to nominate a Supervisor to stand for election, which procedures may discourage or deter a potential acquiror from conducting a solicitation of proxies to elect the acquiror’s own slate of Supervisors or otherwise attempting to obtain control of the Partnership. These nomination procedures may not be revised or repealed, and inconsistent provisions may not be adopted, without the approval of the holders of at least 66-2/3% of the outstanding Common Units. These provisions may have an anti-takeover effect with respect to transactions not approved in advance by our Board of Supervisors, including discouraging attempts that might result in a premium over the market price of the Common Units held by our Unitholders.

Unitholders may not have limited liability in some circumstances.

A number of states have not clearly established limitations on the liabilities of limited partners for the obligations of a limited partnership. Our Unitholders might be held liable for our obligations as if they were general partners if:

	•		a court or government agency determined that we were conducting business in the state but had not complied with the state’s limited partnership statute; or

	•		Unitholders’ rights to act together to remove or replace the General Partner or take other actions under our Partnership Agreement are deemed to constitute ‘‘participation in the control’’ of our business for purposes of the state’s limited partnership statute.

Unitholders may have liability to repay distributions.

Unitholders will not be liable for assessments in addition to their initial capital investment in the Common Units. Under specific circumstances, however, Unitholders may have to repay to us amounts wrongfully returned or distributed to them. Under Delaware law, we may not make a distribution to Unitholders if the distribution causes our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and nonrecourse liabilities are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that a limited partner who receives a distribution of this kind and knew at the time of the distribution that the distribution violated Delaware law will be liable to the limited partnership for the distribution amount for three years from the distribution date. Under Delaware law, an assignee who becomes a substituted limited partner of a limited partnership is liable for the obligations of the assignor to make contributions to the partnership. However, such an assignee is not obligated for liabilities unknown to him at the time he or she became a limited partner if the liabilities could not be determined from the partnership agreement.

If we issue additional limited partner interests or other equity securities as consideration for acquisitions or for other purposes, the relative voting strength of each Unitholder will be diminished over time due to the dilution of each Unitholder’s interests and additional taxable income may be allocated to each Unitholder.

Our Partnership Agreement generally allows us to issue additional limited partner interests and other equity securities without the approval of our Unitholders. Therefore, when we issue additional Common Units or securities ranking on a parity with the Common Units, each Unitholder’s proportionate partnership interest will decrease, and the amount of cash distributed on each Common Unit and the market price of Common Units could decrease. The issuance of additional Common Units will also diminish the relative voting strength of each previously outstanding Common Unit. In addition, the issuance of additional Common Units will, over time, result in the allocation of additional taxable income, representing built-in gains at the time of the new issuance, to those Common Unitholders that existed prior to the new issuance.

Risks Inherent in our Business Operations

Since weather conditions may adversely affect demand for propane, fuel oil and other refined fuels and natural gas, our results of operations and financial condition are vulnerable to warm winters.

Weather conditions have a significant impact on the demand for propane, fuel oil and other refined fuels and natural gas for both heating and agricultural purposes. Many of our customers rely heavily on propane, fuel oil or natural gas as a heating source. The volume of propane, fuel oil and natural gas sold is at its highest during the six-month peak heating season of October through March and is directly affected by the severity of the winter. Typically, we sell approximately two-thirds of our retail propane volume and approximately three-fourths of our retail fuel oil volume during the peak heating season.

Actual weather conditions can vary substantially from year to year, significantly affecting our financial performance. For example, average temperatures in our service territories were 6% warmer than normal for the year ended September 27, 2008 compared to 6% warmer than normal temperatures in fiscal 2007 and 11% warmer than normal temperatures in fiscal 2006, as reported by the National Oceanic and Atmospheric Administration (‘‘NOAA’’). Furthermore, variations in weather in one or more regions in which we operate can significantly affect the total volume of propane, fuel oil and other refined fuels and natural gas we sell and, consequently, our results of operations. Variations in the weather in the northeast, where we have a greater concentration of higher margin residential accounts and substantially all of our fuel oil and natural gas operations, generally have a greater impact on our operations than variations in the weather in other markets. We can give no assurance that the weather conditions in any quarter or year will not have a material adverse effect on our operations, or that our available cash will be sufficient to pay principal and interest on our indebtedness and distributions to Unitholders.

Sudden increases in the price of propane, fuel oil and other refined fuels and natural gas due to, among other things, our inability to obtain adequate supplies from our usual suppliers, may adversely affect our operating results.

Our profitability in the retail propane, fuel oil and refined fuels and natural gas businesses is largely dependent on the difference between our product cost and retail sales price. Propane, fuel oil and other refined fuels and natural gas are commodities, and the unit price we pay is subject to volatile changes in response to changes in supply or other market conditions over which we have no control, including the severity of winter weather and the price and availability of competing alternative energy sources. In general, product supply contracts permit suppliers to charge posted prices at the time of delivery or the current prices established at major supply points, including Mont Belvieu, Texas, and Conway, Kansas. In addition, our supply from our usual sources may be interrupted due to reasons that are beyond our control. As a result, the cost of acquiring propane, fuel oil and other refined fuels and natural gas from other suppliers might be materially higher at least on a short-term basis. Since we may not be able to pass on to our customers immediately, or in full, all increases in our wholesale cost of propane, fuel oil and other refined fuels and natural gas, these increases could reduce our profitability. We engage in transactions to manage the price risk associated with certain of our product costs from time to time in an attempt to reduce cost volatility and to help ensure availability of product during periods of short supply. We can give no assurance that future volatility in propane, fuel oil and natural gas supply costs will not have a material adverse effect on our profitability and cash flow, or that our available cash will be sufficient to pay principal and interest on our indebtedness and distributions to our Unitholders.

Because of the highly competitive nature of the retail propane and fuel oil businesses, we may not be able to retain existing customers or acquire new customers, which could have an adverse impact on our operating results and financial condition.

The retail propane and fuel oil industries are mature and highly competitive. We expect overall demand for propane to remain relatively constant over the next several years, while we expect the overall demand for fuel oil to be relatively flat to moderately declining during the same period. Year-to-year industry volumes of propane and fuel oil are expected to be primarily affected by weather patterns and from competition intensifying during warmer than normal winters, as well as from the impact of a sustained higher commodity price environment on customer conservation.

Propane and fuel oil compete in the alternative energy sources market with electricity, natural gas and other existing and future sources of energy, some of which are, or may in the future be, less costly for equivalent energy value. For example, natural gas is a significantly less expensive source of energy than propane and fuel oil. As a result, except for some industrial and commercial applications, propane and fuel oil are generally not economically competitive with natural gas in areas where natural gas pipelines already exist. The gradual expansion of the nation’s natural gas distribution systems has made natural gas available in many areas that previously depended upon propane or fuel oil. Propane and fuel oil compete to a lesser extent with each other due to the cost of converting from one to the other.

In addition to competing with other sources of energy, our propane and fuel oil businesses compete with other distributors principally on the basis of price, service, availability and portability. Competition in the retail propane business is highly fragmented and generally occurs on a local basis with other large full-service multi-state propane marketers, thousands of smaller local independent marketers and farm cooperatives. Our fuel oil business competes with fuel oil distributors offering a broad range of services and prices, from full service distributors to those offering delivery only. Generally, our existing fuel oil customers, unlike our existing propane customers, own their own tanks. As a result, the competition for these customers is more intense than in our propane business, where our existing customers seeking to switch distributors may face additional transition costs and delays.

As a result of the highly competitive nature of the retail propane and fuel oil businesses, our growth within these industries depends on our ability to acquire other retail distributors, open new customer service centers, add new customers and retain existing customers. We believe our ability to compete effectively depends on reliability of service, responsiveness to customers and our ability to control expenses in order to maintain competitive prices.

Energy efficiency, general economic conditions and technological advances have affected and may continue to affect demand for propane and fuel oil by our retail customers.

The national trend toward increased conservation and technological advances, including installation of improved insulation and the development of more efficient furnaces and other heating devices, has adversely affected the demand for propane and fuel oil by our retail customers which, in turn, has resulted in lower sales volumes to our customers. In addition, recent economic conditions may lead to additional conservation by retail customers to further reduce their heating costs, particularly during periods of sustained higher commodity prices as has been the case over the past three fiscal years. Future technological advances in heating, conservation and energy generation may adversely affect our financial condition and results of operations.

Current conditions in the global capital and credit markets, and general economic pressures may adversely affect our financial position and results of operations.

Our business and operating results are materially affected by worldwide economic conditions. Current conditions in the global capital and credit markets and general economic pressures have led to declining consumer and business confidence, increased market volatility and widespread reduction of business activity generally. As a result of this turmoil, coupled with increasing energy prices, our customers may experience cash flow shortages which may lead to delayed or cancelled plans to purchase our products, and affect the ability of our customers to pay for our products. In addition, disruptions in the U.S. residential mortgage market, increases in mortgage foreclosure rates and failures of lending institutions may adversely affect retail customer demand for our products (in particular, products used for home heating and home comfort equipment) and our business and results of operations.

Our operating results and ability to generate sufficient cash flow to pay principal and interest on our indebtedness, and to pay distributions to Unitholders, may be affected by our ability to continue to control expenses.

The propane and fuel oil industries are mature and highly fragmented with competition from other multi-state marketers and thousands of smaller local independent marketers. Demand for propane and fuel oil is expected to be affected by many factors beyond our control, including, but not limited to, the severity of weather conditions during the peak heating season, customer conservation driven by high energy costs and other economic factors, as well as technological advances impacting energy efficiency. Accordingly, our propane and fuel oil sales volumes and related gross margins may be negatively affected by these factors beyond our control. Our operating profits and ability to generate sufficient cash flow may depend on our ability to continue to control expenses in line with sales volumes. We can give no assurance that we will be able to continue to control expenses to the extent necessary to reduce the effect on our profitability and cash flow from these factors.

The risk of terrorism and political unrest and the current hostilities in the Middle East may adversely affect the economy and the price and availability of propane, fuel oil and other refined fuels and natural gas.

Terrorist attacks and political unrest and the current hostilities in the Middle East may adversely impact the price and availability of propane, fuel oil and other refined fuels and natural gas, as well as 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 us in particular, is not known at this time. An act of terror could result in disruptions of crude oil or natural gas supplies and markets (the sources of propane and fuel oil), and our infrastructure facilities could be direct or indirect targets. Terrorist activity may also hinder our ability to transport propane, fuel oil and other refined fuels if our means of supply transportation, such as rail or pipeline, become damaged as a result of an attack. A lower level of economic activity could result in a decline in energy consumption, which could adversely affect our revenues or restrict our future growth. Instability in the financial markets as a result of terrorism could also affect our ability to raise capital. Terrorist activity and hostilities in the Middle East could likely lead to increased volatility in prices for propane, fuel oil and other refined fuels and natural gas. We have opted to purchase insurance coverage for terrorist acts within our property and casualty insurance programs, but we can give no assurance that our insurance coverage will be adequate to fully compensate us for any losses to our business or property resulting from terrorist acts.

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

Our business is subject to a wide range of federal, state and local laws and regulations related to environmental and health and safety matters including those concerning, among other things, the investigation and remediation of contaminated soil and groundwater and transportation of hazardous materials. These requirements are complex, changing and tend to become more stringent over time. In addition, we are required to maintain various permits that are necessary to operate our facilities, some of which are material to our operations. There can be no assurance that we have been, or will be, at all times in complete compliance with all legal, regulatory and permitting requirements or that we will not incur significant costs in the future relating to such requirements. Violations could result in penalties, or the curtailment or cessation of operations.

Moreover, currently unknown environmental issues, such as the discovery of additional contamination, may result in significant additional expenditures, and potentially significant expenditures also could be required to comply with future changes to environmental laws and regulations or the interpretation or enforcement thereof. Such expenditures, if required, could have a material adverse effect on our business, financial condition or results of operations.

We are subject to operating hazards and litigation risks that could adversely affect our operating results to the extent not covered by insurance.

Our operations are subject to all operating hazards and risks normally associated with handling, storing and delivering combustible liquids such as propane, fuel oil and other refined fuels. As a result, we have been, and are likely to continue to be, a defendant in various legal proceedings and litigation arising in the ordinary course of business. We are self-insured for general and product, workers’ compensation and automobile liabilities up to predetermined amounts above which third-party insurance applies. We cannot guarantee that our insurance will be adequate to protect us from all material expenses related to potential future claims for personal injury and property damage or that these levels of insurance will be available at economical prices, nor that all legal matters that arise will be covered by our insurance programs.

If we are unable to make acquisitions on economically acceptable terms or effectively integrate such acquisitions into our operations, our financial performance may be adversely affected.

The retail propane and fuel oil industries are mature. We foresee only limited growth in total retail demand for propane and flat to moderately declining retail demand for fuel oil. With respect to our retail propane business, because of the long-standing customer relationships that are typical in our industry, the inconvenience of switching tanks and suppliers and propane’s higher cost relative to other energy sources, such as natural gas, it may be difficult for us to acquire new retail propane customers except through acquisitions. As a result, we expect the success of our financial performance to depend, in part, upon our ability to acquire other retail propane and fuel oil distributors or other energy-related businesses and to successfully integrate them into our existing operations and to make cost saving changes. The competition for acquisitions is intense and we can make no assurance that we will be able to acquire other propane and fuel oil distributors or other energy-related businesses on economically acceptable terms or, if we do, to integrate the acquired operations effectively.

Tax Risks to Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes. The Internal Revenue Service (“IRS”) could treat us as a corporation, which would substantially reduce the cash available for distribution to Unitholders.

The anticipated after-tax economic benefit of an investment in our Common Units depends largely on our being treated as a partnership for federal income tax purposes. We believe that, under current law, we will be classified as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us. The IRS may adopt positions that differ from the positions we take. In addition, current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level federal income taxation. In the past, members of Congress have proposed substantive changes to the current federal income tax laws that affect certain publicly-traded partnerships and legislation that would eliminate partnership tax treatment for certain publicly-traded partnerships. Any modification to the U.S. tax laws and interpretations thereof may or may not be applied retroactively. Although no legislation is currently pending that would affect our tax treatment as a partnership, we are unable to predict whether any such changes or other proposals will ultimately be enacted. If we were treated as a corporation for federal income tax purposes, we would be required to pay tax on our income at corporate tax rates (currently a maximum of U.S. federal rate of 35%) and likely would be required to pay state income tax at varying rates. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our Unitholders would be substantially reduced. Therefore, our treatment as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our Unitholders, likely causing a substantial reduction in the value of our Common Units. In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Any such changes could negatively impact our ability to make distributions and also impact the value of an investment in our Common Units.

A successful IRS contest of the federal income tax positions we take may adversely affect the market for our Common Units, and the cost of any IRS contest will reduce our cash available for distribution to our Unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with the positions we take. Any contest with the IRS may materially and adversely impact the market for our Common Units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our Unitholders because the costs will reduce our cash available for distribution.

A Unitholder’s tax liability could exceed cash distributions on its Common Units.

Because our Unitholders are treated as partners to whom we allocate taxable income which could be different in amount than the cash we distribute, a Unitholder is required to pay federal income taxes and, in some cases, state and local income taxes on its allocable share of our income, even if it receives no cash distributions from us. We cannot guarantee that a Unitholder will receive cash distributions equal to its allocable share of our taxable income or even the tax liability to it resulting from that income.

Ownership of Common Units may have adverse tax consequences for tax-exempt organizations and foreign investors.

Investment in Common Units by certain tax-exempt entities and foreign persons raises issues specific to them. For example, virtually all of our taxable income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and thus will be taxable to the Unitholder. Distributions to foreign persons will be reduced by withholding taxes at the highest applicable effective tax rate, and foreign persons will be required to file United States federal tax returns and pay tax on their share of our taxable income. Tax-exempt entities and foreign persons should consult their own tax advisors before investing in our Common Units.

There are limits on a Unitholder’s deductibility of losses.

In the case of taxpayers subject to the passive loss rules (generally, individuals and closely held corporations), any losses generated by us will only be available to offset our future income and cannot be used to offset income from other activities, including other passive activities or investments. Unused losses may be deducted when the Unitholder disposes of its entire investment in us in a fully taxable transaction with an unrelated party. A Unitholder’s share of our net passive income may be offset by unused losses from us carried over from prior years, but not by losses from other passive activities, including losses from other publicly-traded partnerships.

Tax shelter registration could increase the risk of a potential audit by the IRS.

We registered as a ‘‘tax shelter’’ under the law in effect at the time of our initial public offering and were assigned tax shelter registration number 96080000050. The issuance of a tax shelter registration number to us does not indicate that a Common Unit investment in us or the claimed tax benefits have been reviewed, examined or approved by the IRS.

The tax gain or loss on the disposition of Common Units could be different than expected.

A Unitholder who sells Common Units will recognize a gain or loss equal to the difference between the amount realized, including its share of our nonrecourse liabilities, and its adjusted tax basis in the Common Units. Prior distributions in excess of cumulative net taxable income allocated to a Common Unit which decreased a Unitholder’s tax basis in that Common Unit will, in effect, become taxable income if the Common Unit is sold at a price greater than the Unitholder’s tax basis in that Common Unit, even if the price is less than the original cost of the Common Unit. A portion of the amount realized, if the amount realized exceeds the Unitholder’s adjusted basis in that Common Unit, will likely be characterized as ordinary income. Furthermore, should the IRS successfully contest some conventions used by us, a Unitholder could recognize more gain on the sale of Common Units than would be the case under those conventions, without the benefit of decreased income in prior years.

Reporting of partnership tax information is complicated and subject to audits.

We furnish each Unitholder with a Schedule K-1 that sets forth its allocable share of income, gains, losses and deductions. In preparing these schedules, we use various accounting and reporting conventions and adopt various depreciation and amortization methods. We cannot guarantee that these conventions will yield a result that conforms to statutory or regulatory requirements or to administrative pronouncements of the IRS. Further, our income tax return may be audited, which could result in an audit of a Unitholder’s income tax return and increased liabilities for taxes because of adjustments resulting from the audit.

We treat each purchaser of our Common Units as having the same tax benefits without regard to the actual Common Units purchased. The IRS may challenge this treatment, which could adversely affect the value of the Common Units.

Because we cannot match transferors and transferees of Common Units and because of other reasons, uniformity of the economic and tax characteristics of the Common Units to a purchaser of Common Units of the same class must be maintained. To maintain uniformity and for other reasons, we have adopted certain depreciation and amortization conventions which may be inconsistent with Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to a Unitholder. It also could affect the timing of these tax benefits or the amount of gain from the sale of Common Units, and could have a negative impact on the value of our Common Units or result in audit adjustments to a Unitholder’s income tax return.

Unitholders may have negative tax consequences if we default on our debt or sell assets.

If we default on any of our debt obligations, our lenders will have the right to sue us for non-payment. This could cause an investment loss and negative tax consequences for Unitholders through the realization of taxable income by Unitholders without a corresponding cash distribution. Likewise, if we were to dispose of assets and realize a taxable gain while there is substantial debt outstanding and proceeds of the sale were applied to the debt, Unitholders could have increased taxable income without a corresponding cash distribution.

The sale or exchange of 50% or more of our Common Units during any twelve-month period will result in a deemed termination (and reconstitution) of the Partnership for federal income tax purposes which would cause Unitholders to be allocated an increased amount of taxable income.

We will be deemed to have terminated (and reconstituted) for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our Common Units within a twelve-month period. Were this to occur, it would, among other things, result in the closing of our taxable year for all Unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income. This would result in Unitholders being allocated an increased amount of taxable income.

ITEM 2. PROPERTIES

As of September 27, 2008, we owned approximately 77% of our customer service center and satellite locations and leased the balance of our retail locations from third parties. We own and operate a 22 million gallon refrigerated, aboveground propane storage facility in Elk Grove, California. Effective October 2, 2007, we sold our 57.5 million gallon underground propane storage cavern in Tirzah, South Carolina. Additionally, we own our principal executive offices located in Whippany, New Jersey.

The transportation of propane requires specialized equipment. The trucks and railroad tank cars utilized for this purpose carry specialized steel tanks that maintain the propane in a liquefied state. As of September 27, 2008, we had a fleet of 14 transport truck tractors, of which we owned three, and 21 railroad tank cars, of which we owned one. In addition, as of September 27, 2008 we had 912 bobtail and rack trucks, of which we owned approximately 42%, 149 fuel oil tankwagons, of which we owned approximately 57%, and 1,182 other delivery and service vehicles, of which we owned approximately 52%. We lease the vehicles we do not own. As of September 27, 2008, we also owned approximately 756,752 customer propane storage tanks with typical capacities of 100 to 500 gallons, 159,253 customer propane storage tanks with typical capacities of over 500 gallons and 252,764 portable propane cylinders with typical capacities of five to ten gallons.

ITEM 3. LEGAL PROCEEDINGS

Litigation

Our operations are subject to all operating hazards and risks normally incidental to handling, storing and delivering combustible liquids such as propane. As a result, we have been, and will continue to be, a defendant in various legal proceedings and litigation arising in the ordinary course of business. We are self-insured for general and product, workers’ compensation and automobile liabilities up to predetermined amounts above which third party insurance applies. We believe that the self-insured retentions and coverage we maintain are reasonable and prudent. Although any litigation is inherently uncertain, based on past experience, the information currently available to us, and the amount of our self-insurance reserves for known and unasserted self-insurance claims (which was approximately $73.0 million at September 27, 2008), we do not believe that these pending or threatened litigation matters, or known claims or known contingent claims, will have a material adverse effect on our results of operations, financial condition or cash flow. For the portion of our estimated self-insurance liability that exceeds our deductibles, we record a corresponding asset related to the amount of the liability covered by insurance (which was approximately $38.8 million at September 27, 2008).

During the first quarter of fiscal 2009, we agreed to settle a litigation involving alleged product liability for approximately $30.0 million. This settlement will be finalized once certain required procedural activities are completed in various jurisdictions, which is expected to occur in the first quarter of fiscal 2009. The matter was covered by insurance above the level of our insurance deductible. As a result of this settlement, in which we denied any liability, we increased the portion of our estimated self-insurance liability that exceeded the insurance deductible and established a corresponding asset of $30.0 million as of September 27, 2008 to accrue for the settlement and subsequent reimbursement from our third party insurance carrier.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

PART II


ITEM 5.	MARKET FOR THE REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF UNITS

(a) Our Common Units, representing limited partner interests in the Partnership, are listed and traded on the New York Stock Exchange (“NYSE”) under the symbol SPH. As of November 24, 2008, there were 754 Common Unitholders of record. The following table presents, for the periods indicated, the high and low sales prices per Common Unit, as reported on the NYSE, and the amount of quarterly cash distributions declared and paid per Common Unit in respect of each quarter.


					Cash Distribution
	Common Unit Price Range				Declared per
	High		Low		Common Unit
Fiscal 2008
First Quarter	$	48.50	$	40.00	$	0.7625
Second Quarter		42.43		34.00		0.7750
Third Quarter		42.60		37.88		0.8000
Fourth Quarter		39.59		33.13		0.8050

Fiscal 2007
First Quarter	$	39.15	$	33.12	$	0.6875
Second Quarter		44.22		35.11		0.7000
Third Quarter		49.58		43.96		0.7125
Fourth Quarter		49.50		38.70		0.7500

We make quarterly distributions to our partners in an aggregate amount equal to our Available Cash (as defined in our Partnership Agreement as adopted effective October 19, 2006, as amended) with respect to such quarter. Available Cash generally means all cash on hand at the end of the fiscal quarter plus all additional cash on hand as a result of borrowings subsequent to the end of such quarter less cash reserves established by the Board of Supervisors in its reasonable discretion for future cash requirements.

We are a publicly traded limited partnership and, other than certain corporate subsidiaries, we are not subject to federal income tax. Instead, Unitholders are required to report their allocable share of our earnings or loss, regardless of whether we make distributions.

(b) Not applicable.

ITEM 6. SELECTED FINANCIAL DATA

The following table presents our selected consolidated historical financial data as derived from our audited consolidated financial statements, certain of which are included elsewhere in this Annual Report. All amounts in the table below, except per unit data, are in thousands.


	Year Ended
	September 27,			September 29,			September 30,			September 24,			September 25,
	2008			2007			2006 (a)			2005			2004 (b)
Statement of Operations Data
Revenues	$	1,574,163		$	1,439,563		$	1,657,130		$	1,615,555		$	1,301,943
Costs and expenses		1,424,035			1,273,482			1,521,316			1,546,531			1,229,578
Restructuring charges and severance costs (c)		—			1,485			6,076			2,775			2,942
Impairment of goodwill (d)		—			—			—			656			3,177
Income before interest expense, loss on debt extinguishment and provision for income taxes (e)		150,128			164,596			129,738			65,593			66,246
Loss on debt extinguishment (f)		—			—			—			36,242			—
Interest expense, net		37,052			35,596			40,680			40,374			40,832
Provision for income taxes		1,903			5,653			764			803			3
Income (loss) from continuing operations (e)		111,173			123,347			88,294			(11,826	)		25,411
Discontinued operations:
Gain on disposal of discontinued operations (g)		43,707			1,887			—			976			26,332
Income from discontinued operations		—			2,053			2,446			2,774			2,561
Net income (loss)		154,880			127,287			90,740			(8,076	)		54,304
Income (loss) from continuing operations per Common Unit — basic		3.39			3.79			2.76			(0.38	)		0.84
Net income (loss) per Common Unit — basic (h)		4.72			3.91			2.84			(0.26	)		1.79
Net income (loss) per Common Unit — diluted (h)		4.70			3.89			2.83			(0.26	)		1.78
Cash distributions declared per unit	$	3.09		$	2.76		$	2.48		$	2.45		$	2.39

Balance Sheet Data (end of period)
Cash and cash equivalents	$	137,698		$	96,586		$	60,571		$	14,411		$	53,481
Current assets		359,551			295,874			235,351			236,803			252,894
Total assets		1,035,713			988,881			945,566			959,305			988,323
Current liabilities, excluding short-term borrowings and current portion of long-term borrowings		223,615			206,011			191,195			193,401			198,907
Total debt		531,772			548,538			548,304			575,295			515,915
Other long-term liabilities		60,250			68,055			105,366			114,493			105,383
Partners’ capital — Common Unitholders		264,231			208,230			170,151			159,199			238,880
Partner’s (deficit) capital — General Partner	$	—		$	—		$	(1,969	)	$	(1,779	)	$	852

Statement of Cash Flows Data
Cash provided by (used in)
Operating activities	$	120,517		$	145,957		$	170,321		$	39,005		$	93,065
Investing activities		36,630			(19,689	)		(19,092	)		(24,631	)		(196,557	)
Financing activities	$	(116,035	)	$	(90,253	)	$	(105,069	)	$	(53,444	)	$	141,208

Other Data
Depreciation and amortization — continuing operations	$	28,394		$	28,790		$	32,653		$	37,260		$	36,236
Depreciation and amortization — discontinued operations		—			452			498			502			507
EBITDA and Adjusted EBITDA (i)		222,229			197,778			165,335			107,105			131,882
Capital expenditures — maintenance and growth (j)		21,819			26,756			23,057			29,301			26,527
Acquisitions	$	—		$	—		$	—		$	—		$	211,181
Retail gallons sold (k)
Propane		386,222			432,526			466,779			516,040			537,330
Fuel oil and refined fuels		76,515			104,506			145,616			244,536			220,469


(a)		Fiscal 2006 includes 53 weeks of operations compared to 52 weeks in each of fiscal 2008, 2007, 2005 and 2004.

(b)		Fiscal 2004 includes the results from our acquisition of substantially all of the assets and operations of Agway Energy from December 23, 2003, the date of acquisition.


(c)		During fiscal 2007, we incurred $1.5 million in charges associated with severance for positions eliminated unrelated to any specific plan of restructuring. During fiscal 2006, we incurred $6.1 million in restructuring charges associated primarily with severance costs from our field realignment efforts initiated during the fourth quarter of fiscal 2005, including the restructuring of our services segment. During fiscal 2005, we incurred $2.8 million in restructuring charges associated primarily with severance costs from the realignment of our field operations. During fiscal 2004, we incurred $2.9 million in restructuring charges to integrate our assets, employees and operations with Agway Energy assets, employees and operations.

(d)		During fiscal 2005, we recorded a non-cash charge of $0.7 million related to the impairment of goodwill in our services segment. During fiscal 2004, we recorded a non-cash charge of $3.2 million related to impairment of goodwill for one of our reporting units acquired in fiscal 1999.

(e)		These amounts include gains from the disposal of property, plant and equipment of $2.3 million for fiscal 2008, $2.8 million for fiscal 2007, $1.0 million for fiscal 2006, $2.0 million for fiscal 2005 and $0.7 million for fiscal 2004.

(f)		During fiscal 2005, we incurred a one-time charge of $36.2 million as a result of our March 31, 2005 debt refinancing to reflect the loss on debt extinguishment associated with a prepayment premium of $32.0 million and the write-off of $4.2 million of unamortized bond issuance costs associated with the previously outstanding senior notes.

(g)		Gain on disposal of discontinued operations for fiscal 2008 of $43.7 million reflects the October 2, 2007 sale of our Tirzah, South Carolina underground granite propane storage cavern, and associated 62-mile pipeline, for $53.7 million in net proceeds (the “Tirzah Sale”). The 57.5 million gallon underground storage cavern is connected to the Dixie Pipeline and provides propane storage for the eastern United States. Gain on disposal of discontinued operations for fiscal 2007 of $1.9 million reflects the exchange, in a non-cash transaction, of nine non-strategic customer service centers for three customer service centers of another company in Alaska, as well as the sale of three additional customer service centers for net cash proceeds of $1.3 million. Gain on disposal of discontinued operations for fiscal 2005 of $1.0 million reflects the finalization of certain purchase price adjustments with the buyer of the customer service centers sold during fiscal 2004. Gain on disposal of discontinued operations for fiscal 2004 of $26.3 million reflects the sale of 24 customer service centers for net cash proceeds of approximately $39.4 million. The gains on disposal have been accounted for within discontinued operations pursuant to Statement of Financial Accounting Standards (“SFAS”) No. 144, ''Accounting for the Impairment or Disposal of Long-Lived Assets’’ (“SFAS 144”). Prior period results of operations attributable to the customer service centers sold during fiscal 2007 were not significant and, as such, prior period results were not reclassified to remove financial results from continuing operations. The prior period results of operations attributable to the sale of our Tirzah, South Carolina storage cavern and associated pipeline and the customer service centers sold in fiscal 2004 have been reclassified to remove financial results from continuing operations.


(h)		Computations of basic earnings per Common Unit for the years ended September 27, 2008 and September 29, 2007 were performed in accordance with SFAS No. 128 “Earnings per Share” (“SFAS 128”) by dividing net income by the weighted average number of outstanding Common Units, and restricted units granted under the 2000 Restricted Unit Plan to retirement-eligible grantees. For fiscal 2006, earnings per Common Unit were performed in accordance with Emerging Issues Task Force consensus 03-6 “Participating Securities and the Two-Class Method Under FAS 128” (“EITF 03-6”), when applicable. EITF 03-6 requires, among other things, the use of the two-class method of computing earnings per unit when participating securities exist. The two-class method is an earnings allocation formula that computes earnings per unit for each class of Common Unit and participating security according to distributions declared and participating rights in undistributed earnings, as if all of the earnings were distributed to the limited partners and the General Partner (inclusive of the previously outstanding IDRs of the General Partner which were considered participating securities for purposes of the two-class method). Net income was allocated to the Common Unitholders and the General Partner in accordance with their respective partnership ownership interests, after giving effect to any priority income allocations for IDRs of the General Partner. As a result of the GP Exchange Transaction on October 19, 2006, the two-class method of computing income per Common Unit under EITF 03-6 is no longer applicable.

		The requirements of EITF 03-6, which we adopted at the end of fiscal 2004, do not apply to the computation of earnings per Common Unit in periods in which a net loss is reported and therefore did not have any impact on loss per Common Unit for the year ended September 24, 2005, nor did it have any impact on income per Common Unit for the year ended September 25, 2004. Application of the two-class method under EITF 03-6 had a negative impact on income per Common Unit of $0.07 for the year ended September 30, 2006 compared to the computation under SFAS No. 128. Basic net income (loss) per Common Unit for the years ended September 24, 2005 and September 25, 2004 was computed under SFAS 128 by dividing net income (loss), after deducting our General Partner’s interest, by the weighted average number of outstanding Common Units. Diluted net income (loss) per Common Unit for these same periods was computed by dividing net income (loss), after deducting our General Partner’s interest, by the weighted average number of outstanding Common Units and unvested restricted units under our 2000 Restricted Unit Plan. For purposes of the computation of income per Common Unit for the year ended September 29, 2007, earnings that would have been allocated to the General Partner for the period prior to the GP Exchange Transaction were not significant.

(i)		EBITDA represents net income before deducting interest expense, income taxes, depreciation and amortization. Our management uses EBITDA as a measure of liquidity and we are including it because we believe that it provides our investors and industry analysts with additional information to evaluate our ability to meet our debt service obligations and to pay our quarterly distributions to holders of our Common Units. In addition, certain of our incentive compensation plans covering executives and other employees utilize EBITDA as the performance target. We use the term Adjusted EBITDA to reflect the presentation of EBITDA for the year ended September 24, 2005 exclusive of the impact of the non-cash charge for loss on debt extinguishment in the amount of $36.2 million. We use this non-GAAP financial measure in order to assist industry analysts and investors in assessing our liquidity on a year-over-year basis. Moreover, our revolving credit


		agreement requires us to use EBITDA or Adjusted EBITDA as a component in calculating our leverage and interest coverage ratios. EBITDA and Adjusted EBITDA are not recognized terms under generally accepted accounting principles (“GAAP”) and should not be considered as alternatives to net income or net cash provided by operating activities determined in accordance with GAAP. Because EBITDA as determined by us excludes some, but not all, items that affect net income, it may not be comparable to EBITDA or similarly titled measures used by other companies. The following table sets forth (i) our calculations of EBITDA and Adjusted EBITDA and (ii) a reconciliation of EBITDA and Adjusted EBITDA, as so calculated, to our net cash provided by operating activities (amounts in thousands):


	Fiscal			Fiscal			Fiscal			Fiscal			Fiscal
	2008			2007			2006			2005			2004

Net income (loss)	$	154,880		$	127,287		$	90,740		$	(8,076	)	$	54,304
Add:
Provision for income taxes		1,903			5,653			764			803			3
Interest expense, net		37,052			35,596			40,680			40,374			40,832
Depreciation and amortization
Continuing operations		28,394			28,790			32,653			37,260			36,236
Discontinued operations		—			452			498			502			507

EBITDA		222,229			197,778			165,335			70,863			131,882
Loss on debt extinguishment		—			—			—			36,242			—

Adjusted EBITDA		222,229			197,778			165,335			107,105			131,882
Add (subtract):
Provision for income taxes — current		(626	)		(1,853	)		(764	)		(803	)		(3	)
Loss on debt extinguishment		—			—			—			(36,242	)		—
Interest expense, net		(37,052	)		(35,596	)		(40,680	)		(40,374	)		(40,832	)
Compensation cost recognized under Restricted Unit Plan		2,156			3,014			2,221			1,805			1,171
Gain on disposal of property, plant and equipment, net		(2,252	)		(2,782	)		(1,000	)		(2,043	)		(715	)
Gain on disposal of discontinued operations		(43,707	)		(1,887	)		—			(976	)		(26,332	)
Pension settlement charge		—			3,269			4,437			—			5,337
Changes in working capital and other assets and liabilities		(20,231	)		(15,986	)		40,772			10,533			22,557


Net cash provided by operating activities	$	120,517		$	145,957		$	170,321		$	39,005		$	93,065


(j)		Our capital expenditures fall generally into two categories: (i) maintenance expenditures, which include expenditures for repair and replacement of property, plant and equipment; and (ii) growth capital expenditures which include new propane tanks and other equipment to facilitate expansion of our customer base and operating capacity.

(k)		Over the course of the past several years, retail gallons sold in both segments have been adversely affected by the elimination of certain lower margin accounts, particularly industrial, commercial and agricultural propane accounts and low sulfur diesel and gasoline accounts, as well as the impact of enhanced efficiencies in home heating and customer conservation attributable to the high price environment.


ITEM 7.		MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following is a discussion of our financial condition and results of operations, which should be read in conjunction with our consolidated financial statements and notes thereto included elsewhere in this Annual Report.

Executive Overview

The following are factors that regularly affect our operating results and financial condition. In addition, our business is subject to the risks and uncertainties described in Item 1A of this Annual Report.

Product Costs and Supply

The level of profitability in the retail propane, fuel oil, natural gas and electricity businesses is largely dependent on the difference between retail sales price and product cost. The unit cost of our products, particularly propane, fuel oil and natural gas, is subject to volatility as a result of product supply or other market conditions, including, but not limited to, economic and political factors impacting crude oil and natural gas supply or pricing. We enter into product supply contracts that are generally one-year agreements subject to annual renewal, and we also purchase product on the open market. We attempt to reduce our exposure to volatile product costs by short-term pricing arrangements, rather than long-term fixed price supply arrangements. Our propane supply contracts typically provide for pricing based upon index formulas using the posted prices established at major supply points such as Mont Belvieu, Texas, or Conway, Kansas (plus transportation costs) at the time of delivery. In certain instances, and when market conditions (relating to our supply arrangements and risk management activities) are favorable, as was the case in the propane and fuel oil markets during the first half of fiscal 2007, we are able to purchase product under our supply arrangements at a discount to the spot market. However, such favorable market conditions and margin opportunities were not present in fiscal 2008. Rather, very challenging market conditions in fiscal 2008, characterized by an extreme rise in commodity prices (particularly during the third quarter) coupled with lower volumes resulted in the recognition of realized losses under our hedging and risk management activities which were not fully offset by the sales of the physical inventory as more fully described under “Hedging and Risk Management Activities” below.

To supplement our annual purchase requirements, we may utilize forward fixed price purchase contracts to acquire a portion of the propane that we resell to our customers, which allows us to manage our exposure to unfavorable changes in commodity prices and to assure adequate physical supply. The percentage of contract purchases, and the amount of supply contracted for under forward contracts at fixed prices, will vary from year to year based on market conditions.

Product cost changes can occur rapidly over a short period of time and can impact profitability. There is no assurance that we will be able to pass on product cost increases fully or immediately, particularly when product costs increase rapidly. Therefore, average retail sales prices can vary significantly from year to year as product costs fluctuate with propane, fuel oil, crude oil and natural gas commodity market conditions. In addition, in periods of sustained higher commodity prices, as has been experienced over the past several fiscal years, retail sales volumes have been negatively impacted by customer conservation efforts.

Seasonality

The retail propane and fuel oil distribution businesses, as well as the natural gas marketing business, are seasonal because of the primary use for heating in residential and commercial buildings. Historically, approximately two-thirds of our retail propane volume is sold during the six-month peak heating season from October through March. The fuel oil business tends to experience greater seasonality given its more limited use for space heating and approximately three-fourths of our fuel oil volumes are sold between October and March. Consequently, sales and operating profits are concentrated in our first and second fiscal quarters. Cash flows from operations, therefore, are greatest during the second and third fiscal quarters when customers pay for product purchased during the winter heating season. We expect lower operating profits and either net losses or lower net income during the period from April through September (our third and fourth fiscal quarters). To the extent necessary, we will reserve cash from the second and third quarters for distribution to holders of our Common Units in the first and fourth fiscal quarters.

Weather

Hedging and Risk Management Activities

We engage in hedging and risk management activities to reduce the effect of price volatility on our product costs and to ensure the availability of product during periods of short supply. We enter into propane forward and option agreements with third parties, and use fuel oil futures and option contracts traded on the New York Mercantile Exchange (“NYMEX”), to purchase and sell propane and fuel oil at fixed prices in the future. The majority of the futures, forward and option agreements are used to hedge price risk associated with propane and fuel oil physical inventory, as well as, in certain instances, forecasted purchases of propane or fuel oil. Forward contracts are generally settled physically at the expiration of the contract and futures are generally settled in cash at the expiration of the contract. Although we use derivative instruments to reduce the effect of price volatility associated with priced physical inventory and forecasted transactions, we do not use derivative instruments for speculative trading purposes. Risk management activities are monitored by an internal Commodity Risk Management Committee, made up of five members of management and reporting to our Auditing Committee, through enforcement of our Hedging and Risk Management Policy.

As a result of various market factors during the first half of fiscal 2007, particularly commodity price volatility during the first four months of the fiscal year, we experienced additional margin opportunities due to favorable pricing under certain supply arrangements and from our hedging and risk management activities. These market conditions generated additional operating profit of approximately $14.7 million during fiscal 2007 compared to fiscal 2008. Supply and risk management transactions may not always result in increased product margins and there can be no assurance that the favorable market conditions that contributed to incremental margin during the first half of fiscal 2007 will be present in the future in order to provide the additional margin opportunities. Very different and challenging factors existed in fiscal 2008. In fact, as a result of the rise in commodity prices in fiscal 2008, particularly during the third quarter, we realized losses under our futures positions utilized to hedge price risk associated with a portion of our priced physical inventory. Under our hedging and risk management strategy, realized gains or losses on futures contracts will typically offset losses or gains on the physical inventory once the product is sold to customers at market prices. However, as a result of lower than expected volumes primarily attributable to customer conservation, the timing was such that these losses were not fully offset by sales of the physical product. Accordingly, our risk management activities had a negative effect on earnings of approximately $10.8 million during fiscal 2008 as a result of realized losses on futures contracts that were not fully offset by sales of physical product. See Item 7A of this Annual Report for a further discussion of risk management activities.

Critical Accounting Policies and Estimates

Our significant accounting policies are summarized in Note 2, “Summary of Significant Accounting Policies,” included within the Notes to Consolidated Financial Statements section elsewhere in this Annual Report.

Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated, requiring management to make certain assumptions with respect to values or conditions that cannot be known with certainty at the time the financial statements are prepared. The preparation of financial statements in conformity with GAAP 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 revenues and expenses during the reporting period. We are also subject to risks and uncertainties that may cause actual results to differ from estimated results. Estimates are used when accounting for depreciation and amortization of long-lived assets, employee benefit plans, self-insurance and litigation reserves, environmental reserves, allowances for doubtful accounts, asset valuation assessments and valuation of derivative instruments. We base our estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known to us. Management has reviewed these critical accounting estimates and related disclosures with the Audit Committee of our Board of Supervisors. We believe that the following are our critical accounting estimates:

Allowances for Doubtful Accounts. We maintain allowances for doubtful accounts for estimated losses resulting from the inability of our customers to make required payments. We estimate our allowances for doubtful accounts using a specific reserve for known or anticipated uncollectible accounts, as well as an estimated reserve for potential future uncollectible accounts taking into consideration our historical write-offs. If the financial condition of one or more of our customers were to deteriorate resulting in an impairment in their ability to make payments, additional allowances could be required. As a result of our large customer base, which is comprised of more than 900,000 customers, no individual customer account is material. Therefore, while some variation to actual results occurs, historically such variability has not been material. Schedule II, Valuation and Qualifying Accounts, provides a summary of the changes in our allowances for doubtful accounts during the period.

Pension and Other Postretirement Benefits. We estimate the rate of return on plan assets, the discount rate used to estimate the present value of future benefit obligations and the expected cost of future health care benefits in determining our annual pension and other postretirement benefit costs. While we believe that our assumptions are appropriate, significant differences in our actual experience or significant changes in market conditions may materially affect our pension and other postretirement benefit obligations and our future expense. See “Liquidity and Capital Resources – Pension Plan Assets and Obligations” below for additional disclosure regarding pension benefits.

With other assumptions held constant, an increase of 100 basis points in the discount rate would have an estimated favorable impact of $0.3 million on net pension and postretirement benefit costs and an increase of 100 basis points in the expected rate of return assumption would have an estimated favorable impact of $1.5 million on net pension and postretirement benefit costs. With other assumptions held constant, a decrease of 100 basis points in the discount rate would have an estimated unfavorable impact of $0.2 million on net pension and postretirement benefit costs and a decrease of 100 basis points in the expected rate of return assumption would have an estimated unfavorable impact of $1.5 million on net pension and postretirement benefit costs.

Self-Insurance Reserves. Our accrued insurance reserves represent the estimated costs of known and anticipated or unasserted claims under our general and product, workers’ compensation and automobile insurance policies. Accrued insurance provisions for unasserted claims arising from unreported incidents are based on an analysis of historical claims data. For each claim, we record a self-insurance provision up to the estimated amount of the probable claim utilizing actuarially determined loss development factors applied to actual claims data. Our self-insurance provisions are susceptible to change to the extent that actual claims development differs from historical claims development. We maintain insurance coverage wherein our net exposure for insured claims is limited to the insurance deductible, claims above which are paid by our insurance carriers. For the portion of our estimated self-insurance liability that exceeds our deductibles, we record an asset related to the amount of the liability expected to be paid by the insurance companies. Historically, we have not experienced significant variability in our actuarial estimates for claims incurred but not reported. Accrued insurance provisions for reported claims are reviewed at least quarterly, and our assessment of whether a loss is probable and/or reasonably estimable is updated as necessary. Due to the inherently uncertain nature of, in particular, product liability claims, the ultimate loss may differ materially from our estimates. However, because of the nature of our insurance arrangements, those material variations historically have not, nor are they expected in the future to have, a material impact on our results of operations or financial position.

Derivative Instruments and Hedging Activities. See Item 7A of this Annual Report for information about accounting for derivative instruments and hedging activities.

Results of Operations and Financial Condition

Fiscal 2008 presented a challenging operating environment characterized by a volatile commodity price environment, continued customer conservation, relatively mild temperatures during the peak winter heating season and a general slowdown in the economy. However, the steps taken by us over the past several years to streamline our operating platform, drive operational efficiencies and reduce costs have helped to mitigate the potential negative effect on our operating results and financial position from these external factors. Net income for fiscal 2008 amounted to $154.9 million, or $4.72 per Common Unit, an increase of $27.6 million, or 21.7%, compared to net income of $127.3 million, or $3.91 per Common Unit, in fiscal 2007. EBITDA (as defined and reconciled below) increased $24.4 million, or 12.3%, to $222.2 million in fiscal 2008 compared to $197.8 million for fiscal 2007.

From a cash flow perspective, despite the sustained period of high commodity prices, we continue to fund working capital requirements from cash on hand and have not borrowed under our working capital facility since April 2006. In the current period of uncertainty surrounding the credit markets, we ended fiscal 2008 in a strong cash position with more than $137.6 million of cash on hand, which we expect will provide sufficient liquidity to fund our ongoing operations for the foreseeable future without an immediate need to access the capital markets. Based on our financial strength, our fiscal 2008 earnings and our confidence in our operating platform, on October 23, 2008, our Board of Supervisors increased the annualized distribution rate by $0.02 per Common Unit to $3.22 per Common Unit, an increase of 7.3% compared to the annualized distribution rate of $3.00 at the end of fiscal 2007.

Revenues of $1,574.2 million increased $134.6 million, or 9.4%, compared to the prior year due to higher average selling prices associated with higher product costs, partially offset by lower volumes. Retail propane gallons sold for fiscal 2008 decreased 46.3 million gallons, or 10.7%, to 386.2 million gallons from 432.5 million gallons in fiscal 2007. Sales of fuel oil and other refined fuels decreased 28.0 million gallons, or 26.8%, to 76.5 million gallons compared to 104.5 million gallons in the prior year. Lower volumes in both segments were attributable to ongoing customer conservation resulting from historically high commodity prices, warmer average temperatures during the peak heating months from October 2007 through March 2008 and, to a lesser extent, the effects of eliminating certain lower margin accounts. Average heating degree days in our service territories were 94% of normal for fiscal 2008 and flat compared to the prior year; however, the winter heating season of fiscal 2008 was warmer than the comparable prior year period, particularly in the northeast where average heating degree days were 7% below normal and the prior year, thus contributing to the lower volumes.

In the commodities markets, average posted prices for propane and fuel oil during fiscal 2008 were 48.6% and 63.8% higher, respectively, compared to fiscal 2007. Costs of products sold increased $174.0 million, or 20.1%, to $1,039.4 million in fiscal 2008 compared to $865.4 million in the prior year, primarily resulting from the rise in commodity prices. As reported throughout much of the prior year, favorable market conditions impacting the supply and pricing structure for propane and fuel oil provided approximately $14.7 million of incremental margin opportunities in fiscal 2007, which were not present in fiscal 2008. In addition, with the dramatic rise in commodity prices, particularly during the third quarter of fiscal 2008, we reported realized losses from risk management activities that were not fully offset by sales of the physical product, resulting in a negative effect of approximately $10.8 million on fiscal 2008 earnings. Costs of products sold for fiscal 2008 also included a $1.8 million unrealized (non-cash) gain attributable to the mark-to-market on certain risk management activities, compared to a $7.6 million unrealized (non-cash) loss in the prior year.

The favorable trend experienced in operating and general and administrative expenses resulting from our efforts to drive efficiencies and reduce costs continued throughout fiscal 2008. Combined operating and general and administrative expenses of $356.2 million decreased $23.1 million, or 6.1%, compared to $379.3 million in the prior year. The most significant cost savings were experienced in payroll and benefit related expenses resulting from a lower headcount and lower variable compensation in line with lower earnings, once adjusted for the significant items described below. In addition, we achieved a modest reduction in costs to operate our fleet as a result of a lower vehicle count and route efficiencies, which more than offset the impact of a dramatic rise in diesel costs.

Net income and EBITDA for fiscal 2008 included a gain (reported within discontinued operations) of $43.7 million from the sale of our Tirzah, South Carolina underground propane storage cavern and associated 62-mile pipeline, which occurred during October 2007. Net income and EBITDA for fiscal 2007 included (i) a non-cash pension settlement charge of $3.3 million to accelerate the recognition of actuarial losses in our defined benefit pension plan as a result of the level of lump sum retirement benefit payments made during fiscal 2007; (ii) severance charges of $1.5 million related to positions eliminated in fiscal 2007; (iii) a $2.0 million gain from the recovery of a substantial portion of legal fees associated with our successful defense of a matter following the 1999 acquisition of certain propane assets in North and South Carolina; and (iv) gains (reported within discontinued operations) of $1.9 million from the sale and exchange of customer service centers considered to be non-strategic.

As we look ahead to fiscal 2009, our anticipated cash requirements include: (i) maintenance and growth capital expenditures of approximately $25.0 million; (ii) approximately $38.4 million of interest and income tax payments; and (iii) assuming distributions remain at the current level, approximately $105.6 million of distributions to Common Unitholders. Based on our current cash position, availability under the Revolving Credit Agreement (unused borrowing capacity under the working capital facility of $119.2 million at September 27, 2008) and expected cash flow from operating activities, we expect to have sufficient funds to meet our current and future obligations. Based on our current forecast of working capital requirements for fiscal 2009, we currently do not expect to borrow under the working capital facility in fiscal 2009.

Fiscal Year 2008 Compared to Fiscal Year 2007

Revenues


(Dollars in thousands)							Percent
	Fiscal		Fiscal		Increase /		Increase /
	2008		2007		(Decrease)		(Decrease)
Revenues
Propane	$	1,132,950	$	1,019,798	$	113,152	11.1%
Fuel oil and refined fuels		288,078		262,076		26,002	9.9%
Natural gas and electricity		103,745		94,352		9,393	10.0%
Services		44,393		56,519		(12,126)	(21.5%)
All other		4,997		6,818		(1,821)	(26.7%)

Total revenues	$	1,574,163	$	1,439,563	$	134,600	9.4%

Total revenues increased $134.6 million, or 9.4%, to $1,574.2 million for the year ended September 27, 2008 compared to $1,439.6 million for the year ended September 29, 2007, due to higher average selling prices associated with higher product costs, partially offset by lower volumes. Volumes in our propane, fuel oil and refined fuels and natural gas and electricity segments were lower in fiscal 2008 compared to the prior year primarily due to ongoing customer conservation resulting from the historically high commodity prices, proactive steps to manage customer credit risk, warmer weather in our service territories during the peak heating months and, to a lesser extent, the effects of eliminating certain lower margin accounts which occurred throughout much of the prior year. From a weather perspective, average heating degree days in our service territories were 94% of normal for fiscal 2008 and flat compared to the prior year; however, the winter heating season of fiscal 2008 was warmer than the comparable prior year period, particularly in the northeast where average heating degree days were 7% below normal and the prior year, thus having a negative effect on volumes.

Revenues from the distribution of propane and related activities of $1,133.0 million for the year ended September 27, 2008 increased $113.2 million, or 11.1%, compared to $1,019.8 million for the year ended September 29, 2007, primarily due to higher average selling prices, partially offset by lower volumes. Retail propane gallons sold in fiscal 2008 decreased 46.3 million gallons, or 10.7%, to 386.2 million gallons from 432.5 million gallons in the prior year. The average posted price of propane during fiscal 2008 increased 48.6% compared to the average posted prices in the prior year, while our average propane selling prices during fiscal 2008 increased approximately 27.0% compared to the prior year. Additionally, revenues from wholesale and other propane activities for the year ended September 27, 2008 decreased $13.2 million compared to the prior year.

Revenues from the distribution of fuel oil and refined fuels of $288.1 million for the year ended September 27, 2008 increased $26.0 million, or 9.9%, from $262.1 million in the prior year, primarily due to higher average selling prices, partially offset by lower volumes. Fuel oil and refined fuels gallons sold in fiscal 2008 decreased 28.0 million gallons, or 26.8%, to 76.5 million gallons from 104.5 million gallons in the prior year. Lower volumes in our fuel oil and refined fuels segment were attributable to the impact of ongoing customer conservation from continued high energy prices combined with our decision to exit certain lower margin diesel and gasoline businesses. Our decision to exit the majority of our low sulfur diesel and gasoline businesses resulted in a reduction in volumes in the fuel oil and refined fuels segment of approximately 9.7 million gallons, or 34.5% of the total volume decline in fiscal 2008 compared to the prior year. The average posted price of fuel oil during fiscal 2008 increased approximately 63.8% compared to the average posted prices in the prior year, while our average selling prices in our fuel oil and refined fuels segment increased approximately 47.4% compared to the prior year period.

Revenues in our natural gas and electricity segment increased $9.3 million, or 10.0%, to $103.7 million for the year ended September 27, 2008 compared to $94.4 million in the prior year as a result of higher average selling prices for both electricity and natural gas, partially offset by lower electricity and natural gas volumes. Revenues in our services segment decreased 21.5% to $44.4 million in fiscal 2008 from $56.5 million in the prior year as a result of the decision to reduce the level of certain installation activities. The focus of our ongoing service offerings are in support of our existing core commodity segments.

Cost of Products Sold


(Dollars in thousands)							Percent
	Fiscal		Fiscal		Increase /		Increase /
	2008		2007		(Decrease)		(Decrease)
Cost of products sold
Propane	$	689,921	$	573,305	$	116,616	20.3%
Fuel oil and refined fuels		247,310		194,213		53,097	27.3%
Natural gas and electricity		87,600		77,116		10,484	13.6%
Services		12,530		16,847	(4,317)			(25.6%)
All other		2,075		3,937	(1,862)		(47.3%)

Total cost of products sold	$	1,039,436	$	865,418	$	174,018	20.1%


As a percent of total revenues	66.0%		60.1%

The cost of products sold reported in the consolidated statements of operations represents the weighted average unit cost of propane and fuel oil sold, as well as the cost of natural gas and electricity, including transportation costs to deliver product from our supply points to storage or to our customer service centers. Cost of products sold also includes the cost of appliances and related parts sold or installed by our customer service centers computed on a basis that approximates the average cost of the products. Unrealized (non-cash) gains or losses from changes in the fair value of derivative instruments that are not designated as cash flow hedges are recorded within cost of products sold. Cost of products sold excludes depreciation and amortization; these amounts are reported separately within the consolidated statements of operations.

Cost of products sold in fiscal 2008 included a $1.8 million unrealized (non-cash) gain representing the net unrealized change in the fair value of derivative instruments during the period, compared to a $7.6 million unrealized (non-cash) loss in the prior year resulting in a decrease of $9.4 million in cost of products sold for the year ended September 27, 2008 compared to the prior year.

Cost of products sold associated with the distribution of propane and related activities of $689.9 million increased $116.6 million, or 20.3%, compared to the prior year. Higher average propane costs resulted in an increase of $189.8 million in cost of products sold during fiscal 2008 compared to the prior year. The impact of the sharp increase in commodity prices was partially offset by lower propane volumes which resulted in a $55.8 million decrease in cost of products sold during fiscal 2008 compared to the prior year. Lower wholesale and other propane revenues, noted above, decreased cost of products sold by approximately $14.2 million compared to the prior year. In addition, the portion of the total net change in the fair value of derivative instruments associated with the propane segment during fiscal 2008, noted above, resulted in a $3.2 million decrease in cost of products sold compared to the prior year.

Cost of products sold associated with our fuel oil and refined fuels segment of $247.3 million increased $53.1 million, or 27.3%, compared to the prior year. Higher average fuel oil costs resulted in an increase of $101.8 million in cost of products sold during fiscal 2008 compared to the prior year period. This increase was partially offset by lower fuel oil sales volumes, which resulted in a $53.3 million decrease in cost of products sold during fiscal 2008 compared to the prior year. In addition, as described above, risk management activities during fiscal 2008 resulted in a $10.8 million increase in cost of products sold compared to the prior year as a result of realized losses on futures contracts that were not fully offset by sales of physical product. The portion of the total net change in the fair value of derivative instruments associated with the fuel oil and refined fuels segment during the period resulted in a $6.2 million decrease in cost of products sold compared to the prior year.

Cost of products sold in our natural gas and electricity segment of $87.6 million increased $10.5 million, or 13.6%, compared to the prior year due to higher average electricity costs and, to a lesser extent, natural gas costs. Cost of products sold in our services segment of $12.5 million decreased $4.3 million, or 25.6%, compared to the prior year primarily due to lower sales volumes.

For the year ended September 27, 2008, total cost of products sold represented 66.0% of revenues compared to 60.1% in the prior year. This increase was primarily attributable to the significant increase in product costs which we were not able to fully pass on to customers, as well as the favorable market conditions discussed above that contributed approximately $14.7 million of incremental margin opportunities in the prior year that were not present in fiscal 2008 and the negative effect of higher commodity prices on our risk management activities which resulted in $10.8 million of realized losses during the second half of fiscal 2008 that were not fully offset by sales of physical product.

Operating Expenses


(Dollars in thousands)	Fiscal		Fiscal				Percent
	2008		2007		Decrease		Decrease
Operating expenses	$	308,071	$	322,852	$	(14,781)		(4.6%)
As a percent of total revenues	19.6%		22.4%

All costs of operating our retail distribution and appliance sales and service operations are reported within operating expenses in the consolidated statements of operations. These operating expenses include the compensation and benefits of field and direct operating support personnel, costs of operating and maintaining our vehicle fleet, overhead and other costs of our purchasing, training and safety departments and other direct and indirect costs of operating our customer service centers.

Operating expenses of $308.1 million for the year ended September 27, 2008 decreased $14.8 million, or 4.6%, compared to $322.9 million in the prior year as a result of our continued efforts to drive operational efficiencies and reduce costs across all operating segments. Payroll and benefit related expenses declined $18.8 million due to lower headcount, as well as lower variable compensation associated with lower earnings in fiscal 2008 compared to the prior year. In addition, vehicle expenditures decreased $0.6 million compared to the prior year, despite a significant increase in the cost of diesel fuel, as a result of a lower vehicle count enabled by ongoing routing efficiencies. Savings from payroll and benefit related expenses and vehicle expenditures were partially offset by higher bad debt expense and increased costs to operate our customer service centers in the high energy price environment.

General and Administrative Expenses


(Dollars in thousands)	Fiscal		Fiscal				Percent
	2008		2007		Decrease		Decrease
General and administrative expenses	$	48,134	$	56,422	$	(8,288)		(14.7%)
As a percent of total revenues		3.1%		3.9%

All costs of our back office support functions, including compensation and benefits for executives and other support functions, as well as other costs and expenses to maintain finance and accounting, treasury, legal, human resources, corporate development and the information systems functions are reported within general and administrative expenses in the consolidated statements of operations.

General and administrative expenses of $48.1 million for the year ended September 27, 2008 decreased $8.3 million, or 14.7%, compared to $56.4 million during the prior year. The decrease was primarily attributable to a reduction in variable compensation resulting from lower earnings in fiscal 2008 compared to the prior year and the reduction of compensation costs recognized under certain long-term incentive plans.

Restructuring Charges and Severance Costs

We did not record any restructuring charges for the year ended September 27, 2008. For the year ended September 29, 2007, we recorded a charge of $1.5 million primarily related to employee termination costs incurred as a result of further refinements to our plan to restructure our services segment.

Depreciation and Amortization


(Dollars in thousands)	Fiscal		Fiscal				Percent
	2008		2007		Decrease		Decrease
Depreciation and amortization	$	28,394	$	28,790	$	(396)		(1.4%)
As a percent of total revenues		1.8%		2.0%

Depreciation and amortization expense of $28.4 million for the year ended September 27, 2008 was relatively unchanged compared to the prior year.

Interest Expense, net


(Dollars in thousands)	Fiscal		Fiscal				Percent
	2008		2007		Increase		Increase
Interest expense, net	$	37,052	$	35,596	$	1,456	4.1%
As a percent of total revenues		2.4%	2.5%

Net interest expense increased $1.5 million, or 4.1%, to $37.1 million for the year ended September 27, 2008, compared to $35.6 million in the prior year as a result of lower market interest rates for short-term investments, which contributed to less interest income earned. As has been the case since April 2006, there were no borrowings under our working capital facility as seasonal working capital needs have been funded through cash on hand and cash flow from operations. We ended fiscal 2008 in a strong cash position with $137.7 million in cash on the consolidated balance sheet.

Discontinued Operations

On October 2, 2007, the Operating Partnership completed the sale of its Tirzah, South Carolina underground granite propane storage cavern, and associated 62-mile pipeline, for approximately $53.7 million in cash, after taking into account certain adjustments. As part of the agreement, we entered into a long-term storage arrangement, not to exceed 7 million propane gallons, with the purchaser of the cavern that will enable us to continue to meet the needs of our retail operations, consistent with past practices. As a result of this sale, we reported a $43.7 million gain on disposal of discontinued operations during the first quarter of fiscal 2008. The results of operations from the Tirzah facilities have been reported within discontinued operations on the consolidated statements of operations for fiscal 2007 and the assets and liabilities have been classified as held for sale on the consolidated balance sheet as of September 29, 2007.

During the first quarter of fiscal 2007, in a non-cash transaction, we disposed of nine customer service centers considered to be non-strategic in exchange for three customer service centers of another company located in Alaska. We reported a $1.0 million gain within discontinued operations during the first quarter of fiscal 2007 for the amount by which the fair value of assets relinquished exceeded the carrying value of the assets relinquished. During fiscal 2007 we also sold three customer service centers for net cash proceeds of $1.3 million and reported a gain on sale within discontinued operations of $0.9 million.

Net Income and EBITDA

We reported net income of $154.9 million, or $4.72 per Common Unit, for the year ended September 27, 2008 compared to net income of $127.3 million, or $3.91 per Common Unit, in the prior year. EBITDA for fiscal 2008 of $222.2 million increased $24.4 million, or 12.3%, compared to EBITDA of $197.8 million in the prior year.

Net income and EBITDA for fiscal 2008 included a gain (reported within discontinued operations) of $43.7 million from our sale of its Tirzah, South Carolina underground storage cavern and associated 62-mile pipeline. By comparison, net income and EBITDA for fiscal 2007 included (i) the non-cash pension settlement charge of $3.3 million; (ii) severance costs of $1.5 million related to positions eliminated; (iii) a gain of $2.0 million from the recovery of a substantial portion of legal fees associated with the successful defense of a matter following the 1999 acquisition of certain propane assets in North and South Carolina; (iv) gains (reported within discontinued operations) of $1.9 million from the sale and exchange of customer service centers considered to be non-strategic; and (v) a non-cash adjustment to the provision for income taxes of $3.8 million.

EBITDA represents net income before deducting interest expense, income taxes, depreciation and amortization. Our management uses EBITDA as a measure of liquidity and we disclose it because we believe that it provides our investors and industry analysts with additional information to evaluate our ability to meet our debt service obligations and to pay our quarterly distributions to holders of our Common Units. In addition, certain of our incentive compensation plans covering executives and other employees utilize EBITDA as the performance target. We use this non-GAAP financial measure in order to assist industry analysts and investors in assessing our liquidity on a year-over-year basis. Moreover, our revolving credit agreement requires us to use EBITDA as a component in calculating our leverage and interest coverage ratios. EBITDA is not a recognized term under GAAP and should not be considered as an alternative to net income or net cash provided by operating activities determined in accordance with GAAP. Because EBITDA as determined by us excludes some, but not all, items that affect net income, it may not be comparable to EBITDA or similarly titled measures used by other companies.

The following table sets forth (i) our calculations of EBITDA and (ii) a reconciliation of EBITDA, as so calculated, to our net cash provided by operating activities:


(Dollars in thousands)	Year Ended
	September 27,		September 29,
	2008		2007
Net income	$	154,880	$	127,287
Add:
Provision for income taxes		1,903		5,653
Interest expense, net		37,052		35,596
Depreciation and amortization — continuing operations		28,394		28,790
Depreciation and amortization — discontinued operations		—		452

EBITDA		222,229		197,778
Add (subtract):
Provision for income taxes — current		(626)		(1,853)
Interest expense, net		(37,052)		(35,596)
Compensation cost recognized under Restricted Unit Plan		2,156		3,014
Gain on disposal of property, plant and equipment, net		(2,252)		(2,782)
Gain on disposal of discontinued operations		(43,707)		(1,887)
Pension settlement charge		—		3,269
Changes in working capital and other assets and liabilities		(20,231)		(15,986)


Net cash provided by operating activities	$	120,517	$	145,957

Fiscal Year 2007 Compared to Fiscal Year 2006

Fiscal 2007 included 52 weeks of operations compared to 53 weeks in the prior year, which has affected operating results for all categories discussed below.

Revenues


(Dollars in thousands)	Fiscal		Fiscal				Percent
	2007		2006		Decrease		Decrease

Revenues
Propane	$	1,019,798	$	1,081,573	$	(61,775)		(5.7%)
Fuel oil and refined fuels		262,076		356,531		(94,455)		(26.5%)
Natural gas and electricity		94,352		122,071		(27,719)		(22.7%)
Services		56,519		87,258		(30,739)		(35.2%)
All other		6,818		9,697		(2,879)		(29.7%)

Total revenues	$	1,439,563	$	1,657,130	$	(217,567)		(13.1%)

Total revenues decreased $217.6 million, or 13.1%, to $1,439.6 million for the year ended September 29, 2007 compared to $1,657.1 million for the year ended September 30, 2006, driven primarily by lower volumes in each of our operating segments, offset to an extent by the higher average selling prices. As reported by NOAA, average temperatures in our service territories were 6% warmer than normal for fiscal 2007 compared to 11% warmer than normal temperatures in fiscal 2006. Lower volumes, despite the colder average temperatures compared to the prior year, were attributed to ongoing customer conservation driven by high energy costs, our ongoing efforts to improve our customer mix by exiting certain lower margin accounts, as well as the impact of the additional week of operations in the prior year.

Revenues from the distribution of propane and related activities of $1,019.8 million for the year ended September 29, 2007 decreased $61.8 million, or 5.7%, compared to $1,081.6 million in the prior year, primarily due to lower volumes, offset to an extent by higher average selling prices. Retail propane gallons sold in fiscal 2007 decreased 34.3 million gallons, or 7.3%, to 432.5 million gallons from 466.8 million gallons in the prior year. Propane volumes sold were negatively affected by customer conservation efforts, and our effort to focus on higher margin residential customers. Average propane selling prices increased 5.1% year-over-year as a result of higher commodity prices for propane and a more favorable customer mix. The average posted price of propane during fiscal 2007 increased 2.6% compared to the average posted prices in the prior year. Additionally, included within the propane segment are revenues from wholesale and risk management activities of $44.8 million for the year ended September 29, 2007, which decreased $29.6 million, or 39.8%, compared to the prior year primarily due to lower risk management activity in the continued high price environment.

Revenues from the distribution of fuel oil and refined fuels of $262.1 million for the year ended September 29, 2007 decreased $94.5 million, or 26.5%, from $356.5 million in the prior year. Fuel oil and refined fuels gallons sold in fiscal 2007 decreased 41.1 million gallons, or 28.2%, to 104.5 million gallons compared to 145.6 million gallons in the prior year. Lower volumes in our fuel oil and refined fuels segment were attributable primarily to our continued efforts to exit certain lower margin gasoline and low sulfur diesel businesses which resulted in an approximate decrease of 21.7 million gallons, or 53% of the total volume decline compared to the prior year. Average selling prices in our fuel oil and refined fuels segment increased 2.4% as a result of the decreased emphasis on lower priced gasoline and diesel businesses. The average posted price of fuel oil during fiscal 2007 decreased 1.2% compared to the average posted prices in the prior year, yet increased sharply during September 2007 compared to the prior year.

Revenues in our natural gas and electricity marketing segment decreased $27.7 million, or 22.7%, to $94.4 million in fiscal 2007 primarily from lower volumes and lower average selling prices for both natural gas and electricity. Revenues in our services segment declined 35.2%, to $56.5 million during fiscal 2007 compared to $87.3 million in the prior year, primarily as a result of the decision during the third quarter of fiscal 2006 to reorganize the services segment and to reduce the level of stand alone installation activities. The focus of our ongoing service offerings are in support of our existing propane, refined fuels and natural gas and electricity segments, thus reducing overall services segment revenues.

Cost of Products Sold


(Dollars in thousands)	Fiscal		Fiscal				Percent
	2007		2006		Decrease		Decrease
Cost of products sold
Propane	$	573,305	$	635,365	$	(62,060)		(9.8%)
Fuel oil and refined fuels		194,213		272,052		(77,839)		(28.6%)
Natural gas and electricity		77,116		102,687		(25,571)		(24.9%)
Services		16,847		35,972		(19,125)		(53.2%)
All other		3,937		5,721		(1,784)		(31.2%)

Total cost of products sold	$	865,418	$	1,051,797	$	(186,379)		(17.7%)


As a percent of total revenues		60.1%		63.5%

Cost of products sold decreased $186.4 million, or 17.7%, to $865.4 million for the year ended September 29, 2007, compared to $1,051.8 million in the prior year. The decrease results primarily from the lower sales volumes described above, as well as the impact of various favorable market factors impacting our supply and risk management activities which provided incremental margin opportunities in fiscal 2007. We attribute approximately $14.7 million of the fiscal 2007 margins to these favorable market conditions that may not be present in the future. Additionally, cost of products sold for fiscal 2007 included a $7.6 million unrealized (non-cash) loss representing the net change in fair values of derivative instruments under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended (“SFAS 133”), compared to a $14.5 million unrealized (non-cash) gain in the prior year (see Item 7A of this Annual Report for information on our policies regarding the accounting for derivative instruments).

Cost of products sold associated with the distribution of propane and related activities of $573.3 million decreased $62.1 million, or 9.8%, compared to the prior year. Lower sales volumes resulted in a $41.3 million decrease in cost of products sold during fiscal 2007 compared to the prior year, partially offset by higher commodity prices which had an unfavorable impact of $0.7 million compared to the prior year. In addition, the impact of mark-to-market adjustments for derivative instruments under SFAS 133 resulted in a $3.8 million increase in cost of products sold as fiscal 2007 included a $1.9 million unrealized (non-cash) loss, compared to a $1.9 million unrealized (non-cash) gain in the prior year. Wholesale and risk management activities resulted in a $25.6 million decrease in cost of products sold compared to the prior year due to lower risk management activities.

Cost of products sold associated with our fuel oil and refined fuels segment of $194.2 million decreased $77.8 million, or 28.6%, compared to the prior year. Lower sales volumes and lower commodity prices resulted in a decrease in cost of products sold of $80.4 million and $15.8 million, respectively, during fiscal 2007 compared to the prior year. These declines were partially offset by the impact of mark-to-market adjustments for derivative instruments under SFAS 133, which resulted in a $18.3 million increase in cost of products sold as fiscal 2007 included a $5.7 million unrealized (non-cash) loss, compared to a $12.6 million unrealized (non-cash) gain in the prior year.

Cost of products sold in our natural gas and electricity segment of $77.1 million decreased $25.6 million, or 24.9%, compared to prior year primarily due to lower revenues.

Cost of products sold in our services segment of $16.8 million decreased $19.1 million, or 53.2%, compared to prior year primarily due to lower revenues and a charge of $3.5 million in fiscal 2006 to reduce the carrying value of service inventory that is no longer actively marketed by our customer service centers.

For the year ended September 29, 2007, total cost of products sold represented 60.1% of revenues compared to 63.5% in the prior year, primarily as a result of an improved customer mix from our decision to exit certain lower margin customers in both the propane and fuel oil and refined fuels segments, as well as the impact of various favorable market factors impacting our supply and risk management activities and the lower services activities.

Operating Expenses


(Dollars in thousands)	Fiscal		Fiscal				Percent
	2007		2006		Decrease		Decrease
Operating expenses	$	322,852	$	373,305	$	(50,453)		(13.5%)
As a percent of total revenues		22.4%		22.5%

Operating expenses of $322.9 million for the year ended September 29, 2007 decreased $50.5 million, or 13.5%, compared to $373.3 million in the prior year, which included an additional week of operations. In fiscal 2007, we realized the full-year effect of the operating efficiencies, lower headcount and lower vehicle count resulting from our field and services reorganizations that began at the end of the third quarter of fiscal 2005 and continued into the beginning of fiscal 2007. The most significant cost savings were experienced in payroll and benefit related expenses which declined $28.5 million, as well as a decrease of $7.1 million in vehicle expenditures and savings in other costs of $16.5 million to operate our customer service centers. These cost savings were offset to an extent by a $2.7 million increase in variable compensation resulting from the improved earnings in fiscal 2007 compared to the prior year. In addition, fiscal 2007 operating expenses include a non-cash pension settlement charge of $3.3 million, which was $1.1 million lower than the prior year charge of $4.4 million, in order to accelerate the recognition of a portion of unrecognized actuarial losses in our defined benefit pension plan as a result of the level of lump sum retirement benefit payments made during each of the respective fiscal years.

General and Administrative Expenses


(Dollars in thousands)	Fiscal		Fiscal				Percent
	2007		2006		Decrease		Decrease
General and administrative expenses	$	56,422	$	63,561	$	(7,139)		(11.2%)
As a percent of total revenues		3.9%		3.8%

General and administrative expenses of $56.4 million for the year ended September 29, 2007 were $7.1 million, or 11.2%, lower compared to $63.6 million in fiscal 2006. The decrease was primarily attributable to a $5.0 million reduction in professional services fees incurred in the prior year associated with the GP Exchange Transaction consummated on October 19, 2006, as well as $4.4 million in higher costs incurred in the prior year associated with our field realignment effort. The reduction in professional services fees also includes a $2.0 million gain from our recovery of a substantial portion of legal fees associated with our successful defense of a matter following the 1999 acquisition of certain propane assets in North and South Carolina. These cost savings were offset to an extent by a $4.3 million increase in variable compensation resulting from the improved earnings in fiscal 2007 compared to the prior year.

Restructuring Charges and Severance Costs

For the year ended September 29, 2007, we recorded a charge of $1.5 million related to severance costs incurred associated with positions eliminated during fiscal 2007 unrelated to a specific plan of restructuring. For the year ended September 30, 2006, we recorded a restructuring charge of $6.1 million related primarily to severance costs incurred to effectuate our field realignment and services restructuring initiatives during fiscal 2006.

Depreciation and Amortization


(Dollars in thousands)	Fiscal		Fiscal				Percent
	2007		2006		Decrease		Decrease
Depreciation and amortization	$	28,790	$	32,653	$	(3,863)		(11.8%)
As a percent of total revenues		2.0%		2.0%

Depreciation and amortization expense for the year ended September 29, 2007 decreased $3.9 million, or 11.8%, compared to the prior year primarily as a result of lower amortization expense on intangible assets that have been fully amortized, coupled with lower depreciation from asset retirements. Fiscal 2006 depreciation and amortization expense included a $1.1 million asset impairment charge associated with our field realignment efforts, as well as the write-down of certain assets.

Interest Expense, net


(Dollars in thousands)	Fiscal		Fiscal				Percent
	2007		2006		Decrease		Decrease
Interest expense, net	$	35,596	$	40,680	$	(5,084)		(12.5%)
As a percent of total revenues		2.5%		2.5%

Net interest expense decreased $5.1 million, or 12.5%, to $35.6 million in fiscal 2007. During fiscal 2007, there were no borrowings under our working capital facility as seasonal working capital needs have been funded through improved cash flow and cash on hand, resulting in lower interest expense. In the prior year period, average borrowings under our working capital facility amounted to $13.4 million with a peak borrowing level of $84.0 million. Additionally, as a result of increased cash on hand, interest income on invested cash has increased compared to the prior year, thus reducing net interest expense.

Discontinued Operations

During the first quarter of fiscal 2007, in a non-cash transaction, we completed a transaction in which we disposed of nine customer service centers considered to be non-strategic in exchange for three customer service centers of another company located in Alaska. We reported a $1.0 million gain within discontinued operations in the first quarter of fiscal 2007 for the amount by which the fair value of assets relinquished exceeded the carrying value of the assets relinquished. As part of our overall business strategy, we continually monitor and evaluate existing operations in order to identify opportunities to optimize return on assets by selectively divesting operations in slower growing or non-strategic markets. During fiscal 2007, we also sold three customer service centers for net cash proceeds of $1.3 million and recorded a gain on sale of $0.9 million which has been accounted for in accordance with SFAS 144.

Net Income and EBITDA

We reported net income of $127.3 million, or $3.91 per Common Unit, for the year ended September 29, 2007 compared to net income of $90.7 million, or $2.84 per Common Unit, in the prior year. EBITDA for fiscal 2007 of $197.8 million increased $32.5 million, or 19.7%, compared to EBITDA of $165.3 million in the prior year.

Net income and EBITDA for fiscal 2007 included (i) the non-cash pension settlement charge of $3.3 million; (ii) severance costs of $1.5 million related to positions eliminated; (iii) a gain of $2.0 million from the recovery of a substantial portion of legal fees associated with the successful defense of a matter following the 1999 acquisition of certain propane assets in North and South Carolina; (iv) gains (reported within discontinued operations) of $1.9 million from the sale and exchange of customer service centers considered to be non-strategic; and (v) a non-cash adjustment to the provision for income taxes – deferred taxes of $3.8 million.

By comparison, EBITDA and net income for fiscal 2006 were unfavorably impacted by $17.5 million and $18.6 million, respectively, as a result of certain significant items relating mainly to (i) $6.1 million of restructuring charges primarily related to severance benefits associated with our field realignment and the restructuring of our services business; (ii) incremental professional services fees of $5.0 million associated with the GP Exchange Transaction consummated on October 19, 2006; (iii) a non-cash pension settlement charge of $4.4 million; (iv) a charge of $2.0 million within cost of products sold to reduce the carrying value of service inventory that will no longer be marketed by our customer service centers; and (v) $1.1 million included within depreciation and amortization expense attributable to impairment of assets affected by the field realignment.

The following table sets forth (i) our calculations of EBITDA and (ii) a reconciliation of EBITDA, as so calculated, to our net cash provided by operating activities:


(Dollars in thousands)	Year Ended
	September 29,		September 30,
	2007		2006

Net income	$	127,287	$	90,740
Add:
Provision for income taxes		5,653		764
Interest expense, net		35,596		40,680
Depreciation and amortization — continuing operations		28,790		32,653
Depreciation and amortization — discontinued operations		452		498

EBITDA		197,778		165,335
Add (subtract):
Provision for income taxes — current		(1,853)		(764)
Interest expense, net		(35,596)		(40,680)
Compensation cost recognized under Restricted Unit Plan		3,014		2,221
Gain on disposal of property, plant and equipment, net		(2,782)		(1,000)
Gain on disposal of discontinued operations		(1,887)		—
Pension settlement charge		3,269		4,437
Changes in working capital and other assets and liabilities		(15,986)		40,772


Net cash provided by operating activities	$	145,957	$	170,321

Liquidity and Capital Resources

Analysis of Cash Flows

Operating Activities. Net cash provided by operating activities for the year ended September 27, 2008 amounted to $120.5 million, a decrease of $25.5 million compared to $146.0 million in the prior year. The decrease was attributable to a $21.2 million decrease in earnings, after adjusting for non-cash items in both periods (deprecation, amortization, compensation costs recognized under our Restricted Unit Plan, gains on disposal of assets, pension settlement charges and deferred tax provision) and a $29.3 million increased investment in working capital, partially offset by a $25.0 million voluntary contribution to our defined benefit pension plan made in fiscal 2007. No pension contributions were made during fiscal 2008.

Net cash provided by operating activities for the year ended September 29, 2007 amounted to $146.0 million, a decrease of $24.3 million compared to $170.3 million in the prior year. The decrease was attributable to a $41.7 million increase in working capital and a $15.0 million increase in voluntary contributions to our defined benefit pension plan compared to the prior year, partially offset by $32.4 million in increased earnings, after adjusting for non-cash items in both periods (depreciation, amortization compensation costs recognized under our Restricted Unit Plan, gains on disposal of assets, pension settlement charges and deferred tax provision). The fiscal 2007 voluntary pension plan contribution of $25.0 million was made to fully fund our estimated accumulated benefit obligation, thus substantially reducing, if not eliminating, our future funding requirements.

Investing Activities. Net cash provided by investing activities of $36.6 million for the year ended September 27, 2008 consisted of the net proceeds from the sale of discontinued operations of $53.7 million and the net proceeds from the sale of property, plant and equipment of $4.7 million, partially offset by capital expenditures of $21.8 million (including $12.0 million for maintenance expenditures and $9.8 million to support the growth of operations). Capital spending in fiscal 2008 decreased $5.0 million, or 18.7%, compared to fiscal 2007 primarily as a result of lower spending on tanks and information technology as much of the incremental spending on our field realignment efforts has been incurred.

Net cash used in investing activities of $19.7 million for the year ended September 29, 2007 consisted of capital expenditures of $26.8 million (including $10.0 million for maintenance expenditures and $16.8 million to support the growth of operations), offset by net proceeds of $5.8 million from the sale of property, plant and equipment and proceeds from the sale of certain customer service centers of $1.3 million. Capital spending in fiscal 2007 increased $3.7 million, or 16.0%, compared to fiscal 2006 primarily as a result of spending on information technology to finalize the integration of systems from the Agway Acquisition, as well as the timing of capital spending for our field realignment efforts, particularly to integrate certain customer service center locations.

Financing Activities. Net cash used in financing activities for the year ended September 27, 2008 of $116.0 million reflects $101.0 million in quarterly distributions to Common Unitholders at a rate of $0.75 per Common Unit in respect of the fourth quarter of fiscal 2007, at a rate of $0.7625 per Common Unit in respect of the first quarter of fiscal 2008, at a rate of $0.775 per Common Unit in respect of the second quarter of fiscal 2008 and at a rate of $0.80 per Common Unit in respect of the third quarter of fiscal 2008, as well as a prepayment of $15.0 million to reduce amounts outstanding under our term loan. There were no borrowings under our working capital facility during fiscal 2008, nor have there been any borrowings since April 2006.

Net cash used in financing activities for the year ended September 29, 2007 of $90.3 million reflects quarterly distributions to Common Unitholders at a rate of $0.6625 per Common Unit in respect of the fourth quarter of fiscal 2006, at a rate of $0.6875 per Common Unit in respect of the first quarter of fiscal 2007, at a rate of $0.70 per Common Unit in respect of the second quarter of fiscal 2007 and at a rate of $0.7125 per Common Unit in respect of the third quarter of fiscal 2007.

Summary of Long-Term Debt Obligations and Revolving Credit Lines

Our long-term borrowings and revolving credit lines consist of $425.0 million in 6.875% senior notes due December 2013 (the “2003 Senior Notes”) and a Revolving Credit Agreement at the Operating Partnership level which provides a five-year $125.0 million term loan due March 31, 2010 (the “Term Loan”) and a separate working capital facility which provides available credit up to $175.0 million. On September 26, 2008 we made a prepayment of $15.0 million on the Term Loan thereby reducing the amount outstanding to $110.0 million. There were no outstanding borrowings under the working capital facility as of September 27, 2008 and there have been no borrowings under our working capital facility since April 2006. We have standby letters of credit issued under the working capital facility of the Revolving Credit Agreement in the aggregate amount of $55.8 million in support of retention levels under our self-insurance programs and certain lease obligations which expire periodically through October 25, 2009. Therefore, as of September 27, 2008 we had available borrowing capacity of $119.2 million under the working capital facility of the Revolving Credit Agreement. Additionally, under the Revolving Credit Agreement our Operating Partnership is authorized to incur additional indebtedness of up to $10.0 million in connection with capital leases and up to $20.0 million in short-term borrowings during the period from December 1 to April 1 in each fiscal year in order to meet working capital needs during periods of peak demand, if necessary. Because of our cash position, operating results and cash flow, we did not make any such short-term borrowings during fiscal 2008.

The 2003 Senior Notes mature on December 15, 2013 and require semi-annual interest payments. We are permitted to redeem some or all of the 2003 Senior Notes any time on or after December 15, 2008 at redemption prices specified in the indenture governing the 2003 Senior Notes. In addition, the 2003 Senior Notes have a change of control provision that would require us to offer to repurchase the notes at 101% of the principal amount repurchased, if the holders of the notes elected to exercise the right of repurchase. Borrowings under the Revolving Credit Agreement, including the Term Loan, bear interest at a rate based upon LIBOR plus an applicable margin. An annual facility fee ranging from 0.375% to 0.50%, based upon certain financial tests, is payable quarterly whether or not borrowings occur.

In connection with the Term Loan, our Operating Partnership also entered into an interest rate swap contract with a notional amount of $125.0 million with the issuing lender. In connection with the $15.0 million prepayment of the Term Loan on September 26, 2008, we also amended the interest rate swap contract to reduce the notional amount by $15.0 million. From an original borrowing date of March 31, 2005 through March 31, 2010, our Operating Partnership paid or will pay a fixed interest rate of 4.66% to the issuing lender on the notional principal amount outstanding, effectively fixing the LIBOR portion of the interest rate at 4.66%. In return, the issuing lender paid or will pay to our Operating Partnership a floating rate, namely LIBOR, on the same notional principal amount. The applicable margin above LIBOR, as defined in the Revolving Credit Agreement, will be paid in addition to this fixed interest rate of 4.66%.

Under the Revolving Credit Agreement, our Operating Partnership must maintain a leverage ratio (the ratio of total debt to EBITDA) of less than 4.0 to 1 and an interest coverage ratio (the ratio of EBITDA to interest expense) of greater than 2.5 to 1 at the Partnership level. Under the 2003 Senior Note indenture, we are generally permitted to make cash distributions equal to Available Cash, as defined, as of the end of the immediately preceding quarter, if no event of default exists or would exist upon making such distributions, and our consolidated fixed charge coverage ratio, as defined, is greater than 1.75 to 1. Under the Revolving Credit Agreement, as long as no default exists or would result, the Partnership is permitted to make cash distributions not more frequently than quarterly in an amount not to exceed Available Cash, as defined, for the immediately preceding fiscal quarter. The Revolving Credit Agreement and the 2003 Senior Notes both contain various restrictive and affirmative covenants applicable to our Operating Partnership and us, respectively. These covenants include (i) restrictions on the incurrence of additional indebtedness and (ii) restrictions on certain liens, investments, guarantees, loans, advances, payments, mergers, consolidations, distributions, sales of assets and other transactions. We were in compliance with all covenants and terms of all of our debt agreements as of September 27, 2008 and September 29, 2007.

Under the Revolving Credit Agreement, proceeds from the sale, transfer or other disposition of any asset of the Operating Partnership, other than the sale of inventory in the ordinary course of business, in excess of $15 million must be used to acquire productive assets within twelve months of receipt of the proceeds. Any proceeds not used within twelve months of receipt to acquire productive assets must be used to prepay the outstanding principal of the Term Loan. As noted above, we prepaid $15.0 million of the Term Loan on September 26, 2008 with the remaining available proceeds from the sale of our Tirzah storage facility that were not expected to be used to acquire productive assets within twelve months of receipt. An additional $2.0 million prepayment was made on November 10, 2008, representing the remaining amount to be prepaid from the net proceeds from the Tirzah Sale.

While we do not expect to utilize our working capital facility to fund our ongoing operational needs for the foreseeable future, we have performed an evaluation of the financial institutions supporting our Revolving Credit Agreement in order to assess their ability to provide capital under the working capital facility, if necessary. Our Revolving Credit Agreement is supported by a diverse group of thirteen financial institutions. Management believes that we maintain strong relationships with the financial institutions within our current bank group and, to the extent necessary, will have sufficient access to the unused portion of the working capital facility ($119.2 million as of September 27, 2008 after considering outstanding letters of credit). Our Revolving Credit Agreement matures in March 2010 and we will begin the process of renewing the agreement during the second quarter of fiscal 2009.

Partnership Distributions

We are required to make distributions in an amount equal to all of our Available Cash, as defined in the Partnership Agreement, as amended, 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 the Partnership Agreement, generally means all cash on hand at the end of the respective fiscal quarter less the amount of cash reserves established by the Board of Supervisors in its reasonable discretion for future cash requirements. These reserves are retained for the proper conduct of our business, the payment of debt principal and interest and for distributions during the next four quarters. The Board of Supervisors reviews the level of Available Cash on a quarterly basis based upon information provided by management.

On October 23, 2008, we announced a quarterly distribution of $0.805 per Common Unit, or $3.22 on an annualized basis, in respect of the fourth quarter of fiscal 2008 payable on November 10, 2008 to holders of record on November 3, 2008. This quarterly distribution included an increase of $0.005 per Common Unit, or $0.02 per Common Unit on an annualized basis, from the previous quarterly distribution rate representing the nineteenth increase since our recapitalization in 1999 and a 7.3% increase in the quarterly distribution rate since the fourth quarter of the prior year.

Pension Plan Assets and Obligations

Our defined benefit pension plan was frozen to new participants effective January 1, 2000 and, in furtherance of our effort to minimize future increases in our benefit obligations, effective January 1, 2003, all future service credits were eliminated. Therefore, eligible participants will receive interest credits only toward their ultimate defined benefit under the defined benefit pension plan. There were no minimum funding requirements for the defined benefit pension plan during fiscal 2008, 2007 or 2006. However, we made voluntary contributions of $25.0 million and $10.0 million to the defined benefit pension plan during fiscal 2007 and fiscal 2006, respectively, thereby taking proactive steps to improve the funded status of the plan. As of September 27, 2008 and September 29, 2007, the fair value of plan assets exceeded the projected benefit obligation of the defined benefit pension plan by $0.1 million and $5.5 million, respectively, which was recognized on the balance sheet as an asset. Although the projected benefit obligation under the defined benefit pension plan remained fully funded as of September 27, 2008, the funded status declined $5.4 million compared to the prior year due to negative returns on plan assets during fiscal 2008, which were attributable to the negative performance of the markets where the plan’s assets are invested (domestic fixed income securities market, as well as the domestic and international equity markets), offset to a considerable degree by a reduction in the present value of the benefit obligation due to a general increase in market interest rates.

Our investment policies and strategies, as set forth in the Investment Management Policy and Guidelines, are monitored by a Benefits Committee comprised of five members of management. During fiscal 2007, the Benefits Committee proposed and the Board of Supervisors approved contributions to the plan in order to fully fund the projected benefit obligation and changed the plan’s asset allocation to reduce investment risk and more closely match the expected returns on plan assets to the future cash requirements of the plan. The implementation of this strategy resulted in a $25.0 million voluntary contribution in fiscal 2007 from cash on hand and changed the asset allocation to reflect a greater concentration of fixed income securities.

At the end of fiscal 2007, we adopted SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – An Amendment of FASB Statements No. 87, 88, 106 and 132R” (“SFAS 158”), which requires companies to recognize the funded status of pension and other postretirement benefit plans as an asset or liability on sponsoring employers’ balance sheets and to recognize changes in the funded status in comprehensive income (loss) in the year the changes occur. This adoption resulted in a $48.0 million reduction to the prepaid pension asset and a $5.0 million decrease to accrued postretirement liability, with the resulting $43.0 million reduction in our net assets recorded as an adjustment to accumulated other comprehensive loss.

During fiscal 2007, lump sum benefit payments of $10.8 million exceeded the combined service and interest costs of the net periodic pension cost. As a result, pursuant to SFAS No. 88 “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” we recorded a non-cash settlement charge of $3.3 million in order to accelerate recognition of a portion of cumulative unrecognized losses in the defined benefit pension plan. These unrecognized losses were previously accumulated as a reduction to partners’ capital and were being amortized to expense as part of our net periodic pension cost in accordance with SFAS No. 87 “Employers’ Accounting for Pensions.” During fiscal 2008, the amount of the pension benefit obligation settled through lump sum payments was $6.7 million, which did not exceed the settlement threshold of $8.7 million; therefore, a settlement charge was not required to be recognized for fiscal 2008. Additional pension settlement charges may be required in future periods depending on the level of lump sum benefit payments made in future periods.

There can be no assurance that future declines in capital markets, or interest rates, will not have an adverse impact on our results of operations or cash flow. However, with the fully funded status of the plan, coupled with the shift in investment strategy to a higher concentration of fixed income securities, we expect over the long-term that the returns on plan assets should largely fund the annual interest on the accumulated benefit obligation thus maintaining a fully funded status. For purposes of measuring our projected benefit obligations, we increased the discount rate from 6.00% as of September 29, 2007 to 7.625% as of September 27, 2008, reflecting current market rates for debt obligations of a similar duration to our pension obligations. For purposes of computing net periodic pension cost for fiscal 2008, 2007 and 2006, our assumed long-term rate of return on plan assets was 6.00%, 8.00% and 8.00%, respectively, based on the investment mix of our pension asset portfolio, historical asset performance and expectations for future performance. The reduced expected return assumption for fiscal 2008 relative to prior years reflects the shift in asset mix away from equities and into fixed income investments, which was implemented in early fiscal 2008.

We also provide postretirement health care and life insurance benefits for certain retired employees. Partnership employees who were hired prior to July 1993 and retired prior to March 1998 are eligible for health care benefits if they reached a specified retirement age while working for the Partnership. Partnership employees hired prior to July 1993 are eligible for postretirement life insurance benefits if they reach a specified retirement age while working for the Partnership. Effective January 1, 2000, we terminated our postretirement health care benefit plan for all eligible employees retiring after March 1, 1998. All active and eligible employees who were to receive health care benefits under the postretirement plan subsequent to March 1, 1998 were provided an increase to their accumulated benefits under the defined benefit pension plan. Our postretirement health care and life insurance benefit plans are unfunded. Effective January 1, 2006, we changed its postretirement health care plan from a self-insured program to one that is fully insured under which we pay a portion of the insurance premium on behalf of the eligible participants.

Long-Term Debt Obligations and Operating Lease Obligations

Contractual Obligations

The following table summarizes payments due under our known contractual obligations as of September 27, 2008.


(Dollars in thousands)									Fiscal
	Fiscal		Fiscal		Fiscal		Fiscal		2013 and
	2009		2010		2011		2012		thereafter		Total

Long-term debt obligations	$	2,000	$	108,000	$	—	$	—	$	425,000	$	535,000
Future interest payments		34,853		33,303		29,219		29,219		43,828		170,422
Operating lease obligations (a)		13,286		10,409		7,767		5,732		8,452		45,646
Postretirement benefits obligations		1,923		1,879		1,820		1,755		8,637		16,014
Self-insurance obligations (b)		41,404		8,558		6,166		4,281		12,624		73,033
Other contractual obligations		1,151		5,834		1,068		253		4,971		13,277

Total	$	94,617	$	167,983	$	46,040	$	41,240	$	503,512	$	853,392


(a)		Payments exclude costs associated with insurance, taxes and maintenance, which are not material to the operating lease obligations.

(b)		The timing of when payments are due for our self-insurance obligations is based on estimates that may differ from when actual payments are made. In addition, the payments do not reflect amounts to be recovered from our insurance providers, which was $38.8 million as of September 27, 2008 and included in other current assets ($30.0 million) and other assets ($8.8 million) on the consolidated balance sheet.

Additionally, we have standby letters of credit in the aggregate amount of $55.8 million, in support of retention levels under our casualty insurance programs and certain lease obligations, which expire periodically through October 25, 2009.

Operating Leases

We lease certain property, plant and equipment for various periods under noncancelable operating leases, including approximately 52% of our vehicle fleet, approximately 23% of our customer service centers and portions of our information systems equipment. Rental expense under operating leases was $17.7 million, $19.6 million and $27.2 million for fiscal 2008, 2007 and 2006, respectively. Future minimum rental commitments under noncancelable operating lease agreements as of September 27, 2008 are presented in the table above.

Off-Balance Sheet Arrangements

Guarantees

Certain of our operating leases, primarily those for transportation equipment with remaining lease periods scheduled to expire periodically through fiscal 2015, contain residual value guarantee provisions. Under those provisions, we guarantee that the fair value of the equipment will equal or exceed the guaranteed amount upon completion of the lease period, or we will pay the lessor the difference between fair value and the guaranteed amount. Although the fair value of equipment at the end of its lease term has historically exceeded the guaranteed amounts, the maximum potential amount of aggregate future payments we could be required to make under these leasing arrangements, assuming the equipment is deemed worthless at the end of the lease term, is approximately $16.1 million. The fair value of residual value guarantees for outstanding operating leases was de minimis as of September 27, 2008 and September 29, 2007.

Recently Issued Accounting Standards

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”). SFAS 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. It also establishes a fair value hierarchy that prioritizes information used in developing assumptions when pricing an asset or liability. SFAS 157 is effective for fiscal years beginning after November 15, 2007, which is our 2009 fiscal year, which began on September 28, 2008. In February of 2008, the FASB provided an elective one-year deferral of the provisions of SFAS 157 for nonfinancial assets and nonfinancial liabilities that are only measured at fair value on a non-recurring basis. The adoption of SFAS 157 did not have a material effect on our consolidated financial position, results of operations and cash flows.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”). Under SFAS 159, entities may elect to measure specified financial instruments and warranty and insurance contracts at fair value on a contract-by-contract basis, with changes in fair value recognized in earnings each reporting period. SFAS 159 is effective for fiscal years beginning after November 15, 2007, which is our 2009 fiscal year, which began on September 28, 2008. We did not elect the fair value measurement option; accordingly, the adoption of SFAS 159 did not have a material impact on our consolidated financial position, results of operations and cash flows

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an Amendment of ARB No. 51” (“SFAS 160”). SFAS 160 establishes accounting and reporting standards for noncontrolling interests in an entity’s subsidiary and alters the way the consolidated income statement is presented. SFAS 160 is effective for fiscal years beginning on or after December 15, 2008, which will be our 2010 fiscal year beginning September 27, 2009. As of September 27, 2008, all of our subsidiaries were wholly-owned; accordingly, the adoption of SFAS 160 should not have any impact on our consolidated financial position, results of operations and cash flows.

Also in December 2007, the FASB issued a revised SFAS No. 141 “Business Combinations” (“SFAS 141R”). Among other things, SFAS 141R requires an entity to recognize acquired assets, liabilities assumed and any noncontrolling interest at their respective fair values as of the acquisition date, clarifies how goodwill involved in a business combination is to be recognized and measured, and requires the expensing of acquisition-related costs as incurred. SFAS 141R is effective for business combinations entered into in fiscal years beginning on or after December 15, 2008, which will be our 2010 fiscal year beginning September 27, 2009, with early adoption prohibited.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an Amendment of FASB Statement No. 133” (“SFAS 161”). SFAS 161 requires enhanced disclosures about an entity’s objectives for using derivative instruments and related hedged items, how those derivative instruments are accounted for under SFAS 133 and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. SFAS 161 is effective for financial statements for interim or annual periods beginning on or after November 15, 2008, which will be the second quarter of our 2009 fiscal year beginning December 28, 2008. Because it is only a disclosure standard, the adoption of SFAS 161 will not have a material effect on our consolidated financial position, results of operations and cash flows.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

We enter into product supply contracts that are generally one-year agreements subject to annual renewal, and also purchase product on the open market. Our propane supply contracts typically provide for pricing based upon index formulas using the posted prices established at major supply points such as Mont Belvieu, Texas, or Conway, Kansas (plus transportation costs) at the time of delivery. In addition, to supplement our annual purchase requirements, we may utilize forward fixed price purchase contracts to acquire a portion of the propane that we resell to our customers, which allows us to manage our exposure to unfavorable changes in commodity prices and to ensure adequate physical supply. The percentage of contract purchases, and the amount of supply contracted for under forward contracts at fixed prices, will vary from year to year based on market conditions. In certain instances, and when market conditions are favorable as was the case in the propane and fuel oil markets during the first half of fiscal 2007, we are able to purchase product under our supply arrangements at a discount to the market.

Product cost changes can occur rapidly over a short period of time and can impact profitability. We attempt to reduce commodity price risk by pricing product on a short-term basis. The level of priced, physical product maintained in storage facilities and at our customer service centers for immediate sale to our customers will vary depending on several factors, including, but not limited to, price, availability of supply, and demand for a given time of the year. Typically, our on hand priced position does not exceed more than four to eight weeks of our supply needs depending on the time of the year. In the course of normal operations, we routinely enter into contracts such as forward priced physical contracts for the purchase or sale of propane and fuel oil that, under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended (“SFAS 133”), qualify for and are designated as normal purchase or normal sale contracts. Such contracts are exempted from the fair value accounting requirements of SFAS 133 and are accounted for at the time product is purchased or sold under the related contract.

Under our hedging and risk management strategies, we enter into a combination of exchange-traded futures and option contracts, forward contracts and, in certain instances, over-the-counter options (collectively, “derivative instruments”) to manage the price risk associated with priced, physical product and with future purchases of the commodities used in our operations, principally propane and fuel oil, as well as to ensure the availability of product during periods of high demand. We do not use derivative instruments for speculative or trading purposes. Futures and forward contracts require that we sell or acquire propane or fuel oil at a fixed price for delivery at fixed future dates. An option contract allows, but does not require, its holder to buy or sell propane or fuel oil at a specified price during a specified time period. However, the writer of an option contract must fulfill the obligation of the option contract, should the holder choose to exercise the option. At expiration, the contracts are settled by the delivery of the product to the respective party or are settled by the payment of a net amount equal to the difference between the then current price and the fixed contract price or option exercise price. To the extent that we utilize derivative instruments to manage exposure to commodity price risk and commodity prices move adversely in relation to the contracts, we could suffer losses on those derivative instruments when settled. Conversely, if prices move favorably, we could realize gains. Under our hedging and risk management strategy, realized gains or losses on futures contracts will typically offset losses or gains on the physical inventory once the product is sold to customers at market prices.

With the dramatic rise in commodity prices in fiscal 2008, particularly during the third quarter, we reported realized losses from our risk management activities that were not fully offset by sales of physical product, resulting in a negative effect on earnings of approximately $10.8 million during fiscal 2008. As a result of continued market volatility, we made a decision under our risk management strategy to unwind all of our short futures positions during the third quarter of fiscal 2008.

Market Risk

We are subject to commodity price risk to the extent that propane or fuel oil market prices deviate from fixed contract settlement amounts. Futures traded with brokers of the NYMEX require daily cash settlements in margin accounts. Forward and option contracts are generally settled at the expiration of the contract term either by physical delivery or through a net settlement mechanism. Market risks associated with futures, options and forward contracts are monitored daily for compliance with our Hedging and Risk Management Policy which includes volume limits for open positions. Open inventory positions are reviewed and managed daily as to exposures to changing market prices.

Credit Risk

Futures and fuel oil options are guaranteed by the NYMEX and, as a result, have minimal credit risk. We are subject to credit risk with over-the-counter, forward and propane option contracts to the extent the counterparties do not perform. We evaluate the financial condition of each counterparty with which we conduct business and establish credit limits to reduce exposure to the risk of non-performance by our counterparties.

Interest Rate Risk

A portion of our long-term borrowings bear interest at a variable rate based upon LIBOR plus an applicable margin depending on the level of our total leverage. Therefore, we are subject to interest rate risk on the variable component of the interest rate. We manage our interest rate risk by entering into an interest rate swap agreement. On March 31, 2005, we entered into a $125.0 million interest rate swap contract in conjunction with the Term Loan facility under the Revolving Credit Agreement. On September 26, 2008, we amended the interest rate swap contract to reduce the notional amount by $15.0 million, representing the amount of the Term Loan prepaid on that date. The interest rate swap is being accounted for under SFAS 133 and has been designated as a cash flow hedge. Changes in the fair value of the interest rate swap are recognized in other comprehensive income (“OCI”) until the hedged item is recognized in earnings. At September 27, 2008, the fair value of the interest rate swap was $3.2 million representing an unrealized loss and is included within other liabilities with a corresponding debit in accumulated other comprehensive loss.

Derivative Instruments and Hedging Activities

Pursuant to SFAS 133, all of our derivative instruments are reported on the balance sheet, within other current assets or other current liabilities, at their fair values. On the date that futures, forward and option contracts are entered into, we make a determination as to whether the derivative instrument qualifies for designation as a hedge. Changes in the fair value of derivative instruments are recorded each period in current period earnings or OCI, depending on whether a derivative instrument is designated as a hedge and, if so, the type of hedge. For derivative instruments designated as cash flow hedges, we formally assess, both at the hedge contract’s inception and on an ongoing basis, whether the hedge contract is highly effective in offsetting changes in cash flows of hedged items. Changes in the fair value of derivative instruments designated as cash flow hedges are reported in OCI to the extent effective and reclassified into cost of products sold, or interest expense depending on the item being hedged, during the same period in which the hedged item affects earnings. The mark-to-market gains or losses on ineffective portions of cash flow hedges used to hedge future purchases are immediately recognized in cost of products sold. Changes in the fair value of derivative instruments that are not designated as cash flow hedges, and that do not meet the normal purchase and normal sale exemption under SFAS 133, are recorded within cost of products sold as they occur.

At September 27, 2008, the fair value of derivative instruments described above resulted in derivative assets (unrealized gains) of $5.0 million included within prepaid expenses and other current assets and derivative liabilities (unrealized losses) of $0.5 million included within other current liabilities. Cost of products sold included unrealized (non-cash) gains in the amount of $1.8 million for the year ended September 27, 2008 compared to unrealized (non-cash) losses of $7.6 million for the year ended September 29, 2007, attributable to the change in fair value of derivative instruments not designated as cash flow hedges.

Sensitivity Analysis

In an effort to estimate our exposure to unfavorable market price changes in propane or fuel oil related to our open positions under derivative instruments, we developed a model that incorporates the following data and assumptions:

	A.		The actual fixed contract price of open positions as of September 27, 2008 for each of the future periods.

	B.		The estimated future market prices for futures and forward contracts as of September 27, 2008 as derived from the NYMEX for traded propane or fuel oil futures for each of the future periods.

	C.		The market prices determined in B. above were adjusted adversely by a hypothetical 10% change in the future periods and compared to the fixed contract settlement amounts in A. above to project the potential negative impact on earnings that would be recognized for the respective scenario.

Based on the sensitivity analysis described above, the hypothetical 10% adverse change in market prices for each of the future months for which a future or option contract exists indicates either future losses or a reduction in potential future gains of $1.8 million as of September 27, 2008. The above hypothetical change does not reflect the worst case scenario. Actual results may be significantly different depending on market conditions and the composition of the open position portfolio. The average posted price of propane on September 27, 2008 at Mont Belvieu, Texas (a major storage point) was $1.433 per gallon as compared to $1.341 per gallon on September 29, 2007. The average posted price of fuel oil on September 27, 2008 at Linden, New Jersey was $2.8636 per gallon as compared to $2.2379 per gallon on September 29, 2007.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Our Consolidated Financial Statements and the Report of Independent Registered Public Accounting Firm thereon listed on the accompanying Index to Financial Statements (see page F-1) and the Supplemental Financial Information listed on the accompanying Index to Financial Statement Schedule (see page S-1) are included herein.

Selected Quarterly Financial Data

Due to the seasonality of the retail propane business, our first and second quarter revenues and earnings are consistently greater than third and fourth quarter results. The following presents our selected quarterly financial data for the last two fiscal years (unaudited; in thousands, except per unit amounts).


	First			Second			Third			Fourth			Total
	Quarter			Quarter			Quarter			Quarter			Year
Fiscal 2008
Revenues	$	425,109		$	587,097		$	305,476		$	256,481		$	1,574,163
Cost of products sold		277,715			380,757			212,974			167,990			1,039,436
Income (loss) before interest expense and provision for income taxes (a)		51,789			104,375			(4,380	)		(1,656	)		150,128
Income (loss) from continuing operations (a)		41,722			94,523			(13,747	)		(11,325	)		111,173
Discontinued operations:
Gain on disposal of discontinued operations (b)		43,707			—			—			—			43,707
Net income (loss) (a)		85,429			94,523			(13,747	)		(11,325	)		154,880
Net income (loss) from continuing operations per common unit — basic (d)		1.27			2.89			(0.42	)		(0.35	)		3.39
Net income (loss) per common unit — basic (d)		2.61			2.89			(0.42	)		(0.35	)		4.72
Net income (loss) per common unit — diluted (d)		2.60			2.87			(0.42	)		(0.35	)		4.70

Cash (used in) provided by
Operating activities		(41,953	)		50,340			48,601			63,529			120,517
Investing activities		48,875			(3,553	)		(5,419	)		(3,273	)		36,630
Financing activities		(24,539	)		(24,953	)		(25,362	)		(41,181	)		(116,035	)
EBITDA (e)	$	102,555		$	111,482		$	2,779		$	5,413		$	222,229
Retail gallons sold
Propane		111,937			146,252			71,420			56,613			386,222
Fuel oil and refined fuels		23,594			31,435			12,614			8,872			76,515

Fiscal 2007 (f)
Revenues	$	397,908		$	555,111		$	271,454		$	215,090		$	1,439,563
Cost of products sold		230,874			327,347			167,224			139,973			865,418
Income (loss) before interest expense and provision for income taxes (a)		63,062			114,972			7,261			(20,699	)		164,596
Income (loss) from continuing operations (a)		53,084			105,272			(1,751	)		(33,258	)		123,347
Discontinued operations:
Gain on disposal of discontinued operations (b)		1,002			—			203			682			1,887
Income from discontinued operations (c)		568			588			408			489			2,053
Net income (loss) (a)		54,654			105,860			(1,140	)		(32,087	)		127,287
Net income (loss) from continuing operations per common unit — basic (d)		1.65			3.22			(0.05	)		(1.02	)		3.79
Net income (loss) per common unit — basic (d)		1.70			3.24			(0.03	)		(0.99	)		3.91
Net income (loss) per common unit — diluted (d)		1.69			3.22			(0.03	)		(0.99	)		3.89

Cash (used in) provided by
Operating activities		(5,893	)		87,120			46,788			17,942			145,957
Investing activities		(6,663	)		(2,048	)		(5,981	)		(4,997	)		(19,689	)
Financing activities		(21,637	)		(22,464	)		(22,872	)		(23,280	)		(90,253	)
EBITDA (e)	$	71,768		$	123,130		$	15,303		$	(12,423	)	$	197,778
Retail gallons sold
Propane		121,764			166,796			80,042			63,924			432,526
Fuel oil and refined fuels		28,498			43,997			19,144			12,867			104,506


(a)		These amounts include gains from the disposal of property, plant and equipment of $2.3 million for fiscal 2008 and $2.8 million for fiscal 2007.

(b)		Gain on disposal of discontinued operations reflects (i) a $43.7 million gain on the Tirzah Sale during the first quarter of fiscal 2008 for net cash proceeds of $53.7 million; (ii) a $1.0 million gain on the non-cash exchange of nine non-strategic customer service centers for three customer service centers of another company in Alaska during the first quarter of fiscal 2007; (iii) a $0.2 million gain on the sale of one customer service center for net cash proceeds of $0.3 million during the third quarter of fiscal 2007; and (iv) a $0.7 million gain on the sale of two customer service centers for net cash proceeds of $1.0 million during the fourth quarter of fiscal 2007. These gains were accounted for within discontinued operations pursuant to SFAS 144.

(c)		The results of operations from the Tirzah Sale have been reported within discontinued operations.

(d)		Basic net income (loss) per Common Unit is computed under SFAS 128 by dividing net income (loss) by the weighted average number of outstanding Common Units and restricted units granted under the 2000 Restricted Unit Plan to retirement-eligible grantees. Diluted net income per Common Unit is computed by dividing net income (loss) by the weighted average number of outstanding Common Units and unvested restricted units granted under our 2000 Restricted Unit Plan. For purposes of the computation of income per Common Unit for the year ended September 30, 2007, earnings that would have been allocated to the General Partner for the period prior to the GP Exchange Transaction were not significant.

(e)		EBITDA represents net income before deducting interest expense, income taxes, depreciation and amortization. Our management uses EBITDA as a measure of liquidity and we are including it because we believe that it provides our investors and industry analysts with additional information to evaluate our ability to meet our debt service obligations and to pay our quarterly distributions to holders of our Common Units. In addition, certain of our incentive compensation plans covering executives and other employees utilize EBITDA as the performance target. We use this non-GAAP financial measure in order to assist industry analysts and investors in assessing our liquidity on a year-over-year and quarter-to-quarter basis. Moreover, our revolving credit agreement requires us to use EBITDA as a component in calculating our leverage and interest coverage ratios. EBITDA is not a recognized term under GAAP and should not be considered as an alternative to net income or net cash provided by operating activities determined in accordance


		with GAAP. Because EBITDA as determined by us excludes some, but not all, items that affect net income, it may not be comparable to EBITDA or similarly titled measures used by other companies. The following table sets forth (i) our calculations of EBITDA and (ii) a reconciliation of EBITDA, as so calculated, to our net cash provided by operating activities (amounts in thousands):


	First			Second			Third			Fourth			Total
Fiscal 2008	Quarter			Quarter			Quarter			Quarter			Year

Net income (loss)	$	85,429		$	94,523		$	(13,747	)	$	(11,325	)	$	154,880
Add:
Provision for (benefit from) income taxes		1,679			434			(157	)		(53	)		1,903
Interest expense, net		8,388			9,418			9,524			9,722			37,052
Depreciation and amortization		7,059			7,107			7,159			7,069			28,394

EBITDA		102,555			111,482			2,779			5,413			222,229

Add (subtract):
(Provision for) benefit from income taxes — current		(402	)		(190	)		(87	)		53			(626	)
Interest expense, net		(8,388	)		(9,418	)		(9,524	)		(9,722	)		(37,052	)
Compensation cost recognized under Restricted Unit Plan		(67	)		753			817			653			2,156
Gain on disposal of property, plant and equipment, net		(1,429	)		(283	)		(109	)		(431	)		(2,252	)
Gain on disposal of discontinued operations		(43,707	)		—			—			—			(43,707	)
Changes in working capital and other assets and liabilities		(90,515	)		(52,004	)		54,725			67,563			(20,231	)


Net cash (used in) provided by operating activities	$	(41,953	)	$	50,340		$	48,601		$	63,529		$	120,517


	First			Second			Third			Fourth			Total
Fiscal 2007	Quarter			Quarter			Quarter			Quarter			Year

Net income (loss)	$	54,654		$	105,860		$	(1,140	)	$	(32,087	)	$	127,287
Add:
Provision for income taxes		762			378			389			4,124			5,653
Interest expense, net		9,216			9,322			8,623			8,435			35,596
Depreciation and amortization:
Continuing operations		7,010			7,446			7,306			7,028			28,790
Discontinued operations		126			124			125			77			452

EBITDA		71,768			123,130			15,303			(12,423	)		197,778

Add (subtract):
Provision for income taxes — current		(762	)		(378	)		(389	)		(324	)		(1,853	)
Interest expense, net		(9,216	)		(9,322	)		(8,623	)		(8,435	)		(35,596	)
Compensation cost recognized under Restricted Unit Plan		1,297			(137	)		949			905			3,014
Gain on disposal of property, plant and equipment, net		(247	)		(1,815	)		(339	)		(381	)		(2,782	)
Gain on disposal of discontinued operations		(1,002	)		—			(203	)		(682	)		(1,887	)
Pension settlement charge		—			—			—			3,269			3,269
Changes in working capital and other assets and liabilities		(67,731	)		(24,358	)		40,090			36,013			(15,986	)


Net cash (used in) provided by operating activities	$	(5,893	)	$	87,120		$	46,788		$	17,942		$	145,957


(f)		The fourth quarter of fiscal 2007 includes a $3.8 million provision for income taxes related to the utilization of net operating losses in the first quarter of fiscal 2007.


ITEM 9.		CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

DISCLOSURE CONTROLS AND PROCEDURES. The Partnership maintains disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (the “Exchange Act”)) that are designed to provide reasonable assurance that information required to be disclosed in the Partnership’s filings under the Exchange Act is recorded, processed, summarized and reported within the periods specified in the rules and forms of the SEC and that such information is accumulated and communicated to the Partnership’s management, including its principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

Before filing this Annual Report, the Partnership completed an evaluation under the supervision and with the participation of the Partnership’s management, including the Partnership’s principal executive officer and principal financial officer, of the effectiveness of the design and operation of the Partnership’s disclosure controls and procedures as of September 27, 2008. Based on this evaluation, the Partnership’s principal executive officer and principal financial officer concluded that the Partnership’s disclosure controls and procedures were effective at the reasonable assurance level as of September 27, 2008.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING. There have not been any changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) during the quarter ended September 27, 2008, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. Management’s Report on Internal Control over Financial Reporting is included below.

In the ordinary course of business, we review our system of internal control over financial reporting and make changes to our systems and processes to improve controls and increase efficiency, while ensuring that we maintain an effective internal control environment. Changes may include such activities as implementing new, more efficient systems and automating manual processes.

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING. Management of the Partnership is responsible for establishing and maintaining adequate internal control over financial reporting. The Partnership’s internal control over financial reporting is designed to provide reasonable assurance as to the reliability of the Partnership’s financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

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.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Partnership Management

Our Partnership Agreement provides that all management powers over our business and affairs are exclusively vested in our Board of Supervisors and, subject to the direction of the Board of Supervisors, our officers. No Unitholder has any management power over our business and affairs or actual or apparent authority to enter into contracts on behalf of or otherwise to bind us. There are currently seven Supervisors, who serve on the Board of Supervisors pursuant to the terms of the Partnership Agreement. Prior to adoption of the current Partnership Agreement on October 19, 2006, following approval thereof by the Common Unitholders, Common Unitholders elected three Supervisors to serve a three-year term and the General Partner appointed two Supervisors. Under the current Partnership Agreement, all Supervisors are elected by the Common Unitholders for three-year terms and the two Supervisors appointed by the General Partner, Messrs. Alexander and Dunn, will continue to serve until the next Tri-Annual Meeting of the Unitholders (currently scheduled for fiscal 2009), at which meeting all Supervisors will be elected by the Common Unitholders.

On January 31, 2007, acting on authority granted to it under the Partnership Agreement, the Board of Supervisors increased its size from five to seven Supervisors and appointed John D. Collins and Jane Swift to fill the vacancies thereby created, effective April 25, 2007. Mr. Collins and Ms. Swift will continue to serve on the Board of Supervisors until the next Tri-Annual Meeting of the Unitholders, at which time they will be subject to election by the Common Unitholders.

Five Supervisors, who are not officers or employees of the Partnership or its subsidiaries, serve on the Audit Committee with authority to review, at the request of the Board of Supervisors, specific matters as to which the Board of Supervisors believes there may be a conflict of interest in order to determine if the resolution or course of action in respect of such conflict proposed by the Board of Supervisors is fair and reasonable to us. Under the Partnership Agreement, any matter that receives the “Special Approval” of the Audit Committee (i.e., approval by a majority of the members of the Audit Committee) is conclusively deemed to be fair and reasonable to us, is deemed approved by all of our partners and shall not constitute a breach of the Partnership Agreement or any duty stated or implied by law or equity as long as the material facts known to the party having the potential conflict of interest regarding that matter were disclosed to the Audit Committee at the time it gave Special Approval. The Audit Committee also assists the Board of Supervisors in fulfilling its oversight responsibilities relating to (a) integrity of the Partnership’s financial statements and internal control over financial reporting; (b) the Partnership’s compliance with applicable laws, regulations and its code of conduct; (c) independence and qualifications of the independent registered public accounting firm; (d) performance of the internal audit function and the independent registered public accounting firm; and (e) accounting complaints.

Mr. Collins has advised the Board of Supervisors that he currently serves on the audit committees of four public companies, including the Partnership. In accordance with the rules of the NYSE, the Board of Supervisors has determined that Mr. Collins’ simultaneous service on four audit committees would not impair his ability to effectively serve on the Audit Committee of the Partnership’s Board of Supervisors.

The Board of Supervisors has determined that all five members of the Audit Committee, Harold R. Logan, Jr., John Hoyt Stookey, Dudley C. Mecum, John D. Collins and Jane Swift are audit committee financial experts and are independent within the meaning of the NYSE corporate governance listing standards and in accordance with Rule 10A-3 of the Exchange Act, Item 407 of Regulation S-K and the Partnership’s criteria for Supervisor independence (as discussed in Item 13, herein) as of the date of this Annual Report. Mr. Collins, Chairman of the Audit Committee, presides at the regularly scheduled executive sessions of the non-management Supervisors, all of whom are independent, held as part of the meetings of the Audit Committee. Investors and other parties interested in communicating directly with the non-management Supervisors as a group may do so by writing to the Non-Management Members of the Board of Supervisors, c/o Company Secretary, Suburban Propane Partners, L.P., P.O. Box 206, Whippany, New Jersey 07981-0206.

Board of Supervisors and Executive Officers of the Partnership

The following table sets forth certain information with respect to the members of the Board of Supervisors and our executive officers as of November 24, 2008. Officers are appointed by the Board of Supervisors for one-year terms and Supervisors are elected by the Unitholders for three-year terms.


Name	Age		Position With the Partnership
Mark A. Alexander		50	Chief Executive Officer; Member of the Board of Supervisors
Michael J. Dunn, Jr.		59	President; Member of the Board of Supervisors
Michael A. Stivala		39	Chief Financial Officer and Chief Accounting Officer
A. Davin D’Ambrosio		44	Vice President and Treasurer
Paul Abel		55	Vice President, General Counsel and Secretary
Mark Anton, II		51	Vice President — Business Development
Steven C. Boyd		44	Vice President — Operations
Douglas T. Brinkworth		47	Vice President — Supply
Michael M. Keating		55	Vice President — Human Resources and Administration
Mark Wienberg		46	Vice President — Operational Planning
Neil Scanlon		43	Vice President — Information Services
Michael Kuglin		38	Controller
Harold R. Logan, Jr.		64	Member of the Board of Supervisors (Chairman)
John Hoyt Stookey		78	Member of the Board of Supervisors (Chairman of the Compensation Committee)
Dudley C. Mecum		73	Member of the Board of Supervisors
John D. Collins		70	Member of the Board of Supervisors (Chairman of the Audit Committee)
Jane Swift		43	Member of the Board of Supervisors

Mr. Alexander has served as Chief Executive Officer and as a Supervisor since March 1996, and as President from October 1996 until May 2005. He was Executive Vice Chairman from March 1996 through October 1996. From 1989 until joining the Partnership, Mr. Alexander was an officer of Hanson Industries (the United States management division of Hanson plc, a global diversified industrial conglomerate), most recently Senior Vice President – Corporate Development. Mr. Alexander is the sole member of the General Partner. Mr. Alexander is a Director of Kaydon Corporation and a member of its Corporate Governance and Nominating Committee.

Mr. Dunn has served as President since May 2005. From June 1998 until that date he was Senior Vice President, becoming Senior Vice President – Corporate Development in November 2002. Mr. Dunn has served as a Supervisor since July 1998. He was Vice President – Procurement and Logistics from March 1997 until June 1998. Before joining the Partnership, Mr. Dunn was Vice President of Commodity Trading for the investment banking firm of Goldman Sachs & Company (“Goldman Sachs”).

Mr. Stivala has served as Chief Financial Officer and Chief Accounting Officer since October 2007. Prior to that he was Controller and Chief Accounting Officer since May 2005 and Controller since December 2001. Before joining the Partnership, he held several positions with PricewaterhouseCoopers LLP, an international accounting firm, most recently as Senior Manager in the Assurance practice. Mr. Stivala is a Certified Public Accountant and a member of the American Institute of Certified Public Accountants.

Mr. D’Ambrosio has served as Treasurer since November 2002 and was additionally made a Vice President in October 2007. He served as Assistant Treasurer from October 2000 to November 2002 and as Director of Treasury Services from January 1998 to October 2000. Mr. D’Ambrosio joined the Partnership in May 1996 after ten years in the commercial banking industry.

Mr. Abel has served as General Counsel and Secretary since June 2006 and was additionally made a Vice President in October 2007. From May 2005 until June 2006, Mr. Abel was Assistant General Counsel of Velocita Wireless, L.P., the owner and operator of a nationwide wireless data network. From 1998 until May 2005, Mr. Abel was Vice President, Secretary and General Counsel of AXS-One Inc. (formerly known as Computron Software, Inc.), an international business software company.

Mr. Anton has served as Vice President – Business Development since he joined the Partnership in 1999. Prior to joining the Partnership, Mr. Anton worked as an Area Manager for another large multi-state propane marketer and was a Vice President at several large investment banking organizations.

Mr. Boyd has served as Vice President – Operations since October 2008. Prior to that he was Southeast and Western Area Vice President since March 2007, Managing Director – Area Operations since November 2003 and Regional Manager – Northern California since May 1997. Mr. Boyd held various managerial positions with predecessors of the Partnership from 1986 through 1996.

Mr. Brinkworth has served as Vice President – Supply since May 2005. Mr. Brinkworth joined the Partnership in April 1997 after a nine year career with Goldman Sachs and, since joining the Partnership, has served in various positions in the supply area, most recently as Managing Director.

Mr. Keating has served as Vice President – Human Resources and Administration since July 1996. He previously held senior human resource positions at Hanson Industries and Quantum Chemical Corporation (“Quantum”), a predecessor of the Partnership.

Mr. Wienberg has served as Vice President – Operational Planning since October 2007. Prior to that he served as Managing Director, Financial Planning and Analysis from October 2003 to October 2007 and as Director, Financial Planning and Analysis from July 2001 to October 2003. Prior to joining the Partnership, Mr. Wienberg was Assistant Vice President – Finance of International Home Foods Corp., a consumer products manufacturer.

Mr. Scanlon became Vice President – Information Services in November 2008. Prior to that he served as Assistant Vice President – Information Services since November 2007, Managing Director – Information Services from November 2002 to November 2007 and Director – Information Services from April 1997 until November 2002. Prior to joining the Partnership, Mr. Scanlon spent several years with JP Morgan & Co., most recently as Vice President – Corporate Systems and earlier held several positions with Andersen Consulting (“Accenture”), an international systems consulting firm, most recently as Manager.

Mr. Kuglin has served as Controller since October 2007. For the eight years prior to joining the Partnership he held several financial and managerial positions with Alcatel-Lucent, a global communications solutions provider. Prior to Alcatel-Lucent, Mr. Kuglin held several positions with the international accounting firm PricewaterhouseCoopers LLP, most recently Manager in the Assurance practice. Mr. Kuglin is a Certified Public Accountant and a member of the American Institute of Certified Public Accountants.

Mr. Logan has served as a Supervisor since March 1996 and was elected as Chairman of the Board of Supervisors in January 2007. From 2006 to the present, Mr. Logan is a Co-Founder and Director of Basic Materials and Services LLC, an investment company that has invested in companies that provide specialized infrastructure services and materials for the pipeline construction industry and the sand/silica industry. From 2003 to September 2006, Mr. Logan was a Director and Chairman of the Finance Committee of the Board of Directors of TransMontaigne Inc., which provided logistical services (i.e. pipeline, terminaling and marketing) to producers and end-users of refined petroleum products. From 1995 to 2002, Mr. Logan was Executive Vice President/Finance, Treasurer and a Director of TransMontaigne Inc. From 1987 to 1995, Mr. Logan served as Senior Vice President of Finance and a Director of Associated Natural Gas Corporation, an independent gatherer and marketer of natural gas, natural gas liquids and crude oil. Mr. Logan is also a Director of Graphic Packaging Holding Company and Hart Energy Publishing LLP.

Mr. Stookey has served as a Supervisor since March 1996. He was Chairman of the Board of Supervisors from March 1996 through January 2007. From 1986 until September 1993, he was the Chairman, President and Chief Executive Officer of Quantum. He served as non-executive Chairman and a Director of Quantum from its acquisition by Hanson plc in September 1993 until October 1995, at which time he retired. Since then, Mr. Stookey has served as a trustee for a number of non-profit organizations, including founding and serving as non-executive Chairman of Per Scholas Inc. (a non-profit organization dedicated to using technology to improve the lives of residents of the South Bronx) and Landmark Volunteers (places high school students in volunteer positions with non-profit organizations during summer vacations).

Mr. Mecum has served as a Supervisor since June 1996. He has been a managing director of Capricorn Holdings, LLC (a sponsor of and investor in leveraged buyouts) since June 1997. Mr. Mecum was a partner of G.L. Ohrstrom & Co. (a sponsor of and investor in leveraged buyouts) from 1989 to June 1996.

Mr. Collins has served as a Supervisor since April 2007. He served with KPMG, LLP, an international accounting firm, from 1962 until 2000, most recently as senior audit partner of its New York office. He has served as a United States representative on the International Auditing Procedures Committee, a committee of international accountants responsible for establishing international auditing standards. Mr. Collins is a Director of Montpelier Re, Mrs. Fields Famous Brands, LLC and Columbia Atlantic Funds, and serves as a Trustee of LeMoyne College.

Ms. Swift has served as a Supervisor since April 2007. She is the founder of WNP Consulting, LLC, providing expert advice and guidance to early stage education companies. From 2003 – 2006 she was a General Partner at Arcadia Partners, a venture capital firm focused on the education industry. She currently serves on the boards of K12, Inc., Animated Speech Company and Sally Ride Science Inc. and several not-for-profit boards, including The Republican Majority for Choice and Landmark Volunteers, Inc. Prior to joining Arcadia, Ms. Swift served for 15 years in Massachusetts state government, becoming Massachusetts’ first woman governor in 2001.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires our Supervisors, executive officers and holders of ten percent or more of our Common Units to file initial reports of ownership and reports of changes in ownership of our Common Units with the SEC. Supervisors, executive officers and ten percent Unitholders are required to furnish the Partnership with copies of all Section 16(a) forms that they file. Based on a review of these filings, we believe that all such filings were timely made during fiscal 2008.

Codes of Ethics and of Business Conduct

We have adopted a Code of Ethics that applies to our principal executive officer, principal financial officer and principal accounting officer, and a Code of Business Conduct that applies to all of our employees, officers and Supervisors. Copies of our Code of Ethics and our Code of Business Conduct are available without charge from our website at www.suburbanpropane.com or upon written request directed to: Suburban Propane Partners, L.P., Investor Relations, P.O. Box 206, Whippany, New Jersey 07981-0206. Any amendments to, or waivers from, provisions of our Code of Ethics or our Code of Business Conduct that apply to our principal executive officer, principal financial officer and principal accounting officer will be posted on our website.

Corporate Governance Guidelines

We have adopted Corporate Governance Guidelines and Policies in accordance with the NYSE corporate governance listing standards in effect as of the date of this Annual Report. Copies of our Corporate Governance Guidelines are available without charge from our website at www.suburbanpropane.com or upon written request directed to: Suburban Propane Partners, L.P., Investor Relations, P.O. Box 206, Whippany, New Jersey 07981-0206.

Audit Committee Charter

We have adopted a written Audit Committee Charter in accordance with the NYSE corporate governance listing standards in effect as of the date of this Annual Report. The Audit Committee Charter is reviewed periodically to ensure that it meets all applicable legal and NYSE listing requirements. Copies of our Audit Committee Charter are available without charge from our website at www.suburbanpropane.com or upon written request directed to: Suburban Propane Partners, L.P., Investor Relations, P.O. Box 206, Whippany, New Jersey 07981-0206.

Compensation Committee Charter

Five Supervisors, who are not officers or employees of the Partnership or its subsidiaries, serve on the Compensation Committee. We have adopted a Compensation Committee Charter in accordance with the NYSE corporate governance listing standards in effect as of the date of this Annual Report. Copies of our Compensation Committee Charter are available without charge from our website at www.suburbanpropane.com or upon written request directed to: Suburban Propane Partners, L.P., Investor Relations, P.O. Box 206, Whippany, New Jersey 07981-0206.

NYSE Annual CEO Certification

The NYSE requires the Chief Executive Officer of each listed company to submit a certification indicating that the company is not in violation of the Corporate Governance listing standards of the NYSE on an annual basis. Mr. Alexander submitted his Annual CEO Certification for 2008 to the NYSE without qualification.

ITEM 11. EXECUTIVE COMPENSATION

COMPENSATION DISCUSSION AND ANALYSIS

This Compensation Discussion and Analysis provides a review of our executive compensation philosophy, policies and practices with respect to the following executive officers of the Partnership (the “named executive officers”): the Chief Executive Officer, the President, the Chief Financial Officer and the other two most highly compensated executive officers.

Executive Compensation Philosophy and Components

The objectives of our executive compensation program are as follows:

	•		The attraction and retention of talented executives who have the skills and experience required to achieve our goals; and

	•		The alignment of the short-term and long-term interests of our executive officers with the short-term and long-term interests of our Unitholders.

We accomplish these objectives by providing our executives with compensation packages that combine various components that are specifically linked to either short-term or long-term performance measures. Therefore, our executive compensation packages are designed to achieve our overall goal of sustainable, profitable growth by rewarding our executive officers for behaviors that facilitate our achievement of this goal.

The principal components of the compensation we provide to our named executive officers are as follows:

	•		Base salary;

	•		Cash incentives paid under an annual bonus plan;

	•		Long-term Incentive Plan grants; and

	•		Discretionary grants of restricted units under the 2000 Restricted Unit Plan.

We align the short-term and long-term interests of our executive officers with the short-term and long-term interests of our Unitholders by:

	•		Providing our executive officers with an annual incentive target that encourages them to achieve or exceed targeted financial results and operating performance for the fiscal year;

	•		Providing a long-term incentive plan that encourages our executives to implement activities and practices conducive to sustainable, profitable growth because it permits them to share in benefits generated in the future; and

	•		Providing a restricted unit plan that is utilized to retain the services of the participating executive officers over a five-year period while simultaneously encouraging behaviors conducive to the long-term appreciation of our Common Units.

Establishing Executive Compensation

The Compensation Committee (the “Committee”) is responsible for overseeing our executive compensation program. In accordance with its charter, available on our website at www.suburbanpropane.com, the Committee ensures that the compensation packages provided to our executive officers are designed in accordance with our compensation philosophy. The Committee reviews and approves the compensation packages of our managing directors, assistant vice presidents, vice presidents and our named executive officers.

Annually, the Vice President of Human Resources prepares a comprehensive analysis of each executive officer’s past and current compensation to assist the Committee in the assessment and determination of executive compensation packages for the subsequent fiscal year. The Committee considers a number of factors in establishing the compensation packages for each executive officer, including, but not limited to, tenure, scope of responsibility and individual performance. The relative importance assigned to each of these factors by the Committee may differ from executive to executive. The performance of each of our executive officers is continually assessed by the Committee and by our highest-ranking executive officers and also factors into the decision-making process, particularly in relation to promotions and increases in base compensation. In addition, as part of the Committee’s annual review of each executive officer’s fiscal 2008 total compensation package, the Committee was provided with benchmarking data for a relevant peer group of companies for comparison purposes. The benchmarking data is just one of a number of factors considered by the Committee, but is not necessarily the most persuasive factor.

The benchmarking data was derived from the Mercer Human Resource Consulting, Inc. (“Mercer”) Benchmark Database containing information obtained from surveys of over 2,500 organizations and 167 positions which may include similarly-sized national propane marketers. The Committee does not base its benchmarking solely on a peer group of other propane marketers. The use of the Mercer database provides a broad base of compensation benchmarking information for companies of a similar size to Suburban. The peer group used for the Suburban positions consisted of organizations included in the Mercer database that report annual revenues of between $1.0 billion and $2.5 billion per year.

The Committee believes that benchmarking against such companies in determining “total cash compensation opportunities” is appropriate because of the proximity of the Partnership’s headquarters to New York City and the need to realistically compete for skilled executives in an environment shared by numerous other enterprises that seek skilled employees. For this reason, the Committee chooses not to base its benchmarking on the compensation practices of other propane marketers due to the fact that the other, similarly-sized propane marketers compete for employees in vastly different economic environments.

Alternatively, for the reasons below, the Committee decided to include all other propane marketers, structured as publicly traded partnerships, in the peer group it selected for the 2003 Long-Term Incentive Plan (for more on the 2003 Long-Term Incentive Plan, refer to the subheading “2003 Long-Term Incentive Plan” below). Earning a payment under the 2003 Long-Term Incentive Plan is dependent upon the performance (referred to in the plan document as “total return to unitholders”) of our Common Units in comparison to the unit performance of a peer group of eleven other master limited partnerships over a three-year measurement period. Because total return to unitholders is based on unit price appreciation and distributions, both of which are impacted by earnings, this plan was implemented by the Committee to provide an incentive to management to grow the business and to be conservative in regard to the management of expenses, among other things, and, thereby, enhance the return that we provide to our investors. Because master limited partnerships are not taxpaying entities, potentially these entities have more available cash to distribute to their investors than similar businesses that operate as corporations and do pay corporate-level taxes. This sometimes enables master limited partnerships to provide a greater return, in the form of cash distributions, to their investors than similarly situated corporations. As a result of this reasoning, the Committee selected a peer group for the 2003 Long-Term Incentive Plan that included other propane marketers, even though the Committee selected the Mercer database as a tool to benchmark “total cash compensation opportunities.”

In establishing the fiscal 2007 executive compensation packages, the Committee used the median total compensation paid by the peer group to assess whether the “total cash compensation opportunities” that we provide to our executive officers are both competitive and commensurate with each executive officer’s position and corresponding duties. However, in establishing the fiscal 2008 executive compensation packages, due to an overall increase in executive salaries in the New York area, the Committee used the mean of the reported data as its benchmark. Generally speaking, the mean of the reported data is higher than the median. The members of the Committee focused on lessening the shortfalls between the compensation packages that we provide to our executive officers and the mean compensation paid by the companies whose data underlie the Mercer database. The Committee does not, however, have a formal target with respect to the amount of the shortfall it is trying to lessen. Moreover, the Committee does not set specific percentile targets for total compensation of our executive officers compared to the total compensation of the peer group.

In making its decisions regarding our fiscal 2008 executive compensation packages, the Committee first reviewed the total cash compensation opportunities that we provided to our executive officers during fiscal 2007. Each executive officer’s “total cash compensation opportunities” consist of base salary, an annual cash bonus, and 2003 Long-Term Incentive Plan awards. The Committee then compared each executive officer’s total cash compensation opportunity to the total mean cash compensation opportunity for the parallel position in the Mercer study. By focusing on each executive officer’s total cash compensation opportunities as a whole, instead of on single components of compensation such as base salary, the Committee created fiscal 2008 compensation packages for our executive officers that emphasize the performance-based components of compensation.

Role of Executive Officers and Compensation Committee in Compensation Process

The Committee establishes and enforces our general compensation philosophy in consultation with our Chief Executive Officer. The role of our Chief Executive Officer in the executive compensation process is to recommend individual pay adjustments for the executive officers, other than himself, to the Committee based on market conditions, our performance, and individual performance. With the assistance of our Vice President of Human Resources, our Chief Executive Officer presented the Committee with information comparing each executive officer’s compensation to the mean compensation figures provided in the Mercer database.

The Partnership’s sole use of Mercer was to provide the Committee with benchmarking data. Therefore, neither the Chief Executive Officer nor the President met with representatives from Mercer. The information provided by Mercer was derived from a proprietary database maintained by Mercer and, as such, there was no formal consultancy role played by them. The Committee believes that the Mercer benchmarking data, which is provided to the Committee by our Vice President of Human Resources, can be used by the Committee as an objective benchmark on which decisions relative to executive compensation can be based. In the course of its deliberations, the Committee compares the objective data obtained from the Mercer database to the internal analyses prepared by our Vice President of Human Resources.

Among other duties, the Committee has overall responsibility for:

	•		Reviewing and approving compensation of our Chief Executive Officer, President, Chief Financial Officer and our other executive officers;

	•		Reporting to the Board of Supervisors any and all decisions regarding compensation changes for our Chief Executive Officer, President, Chief Financial Officer and our other executive officers;

	•		Evaluating and approving our annual cash bonus plan, long-term incentive plan, restricted unit plan, as well as all other compensation policies and programs;

	•		Administering and interpreting the compensation plans that constitute each component of our executive officers’ compensation packages; and

	•		Engaging consultants, when appropriate, to provide independent, third-party advice on executive officer-related compensation (in prior fiscal years, the Committee engaged Sibson Consulting during fiscal 2004 for benchmarking the fiscal 2005 executive officers’ compensation packages and Mercer during fiscal 2005 for benchmarking our President’s 2006 compensation package).

Allocation Among Components

Under our compensation structure, the mix of base salary, cash bonus and long-term compensation provided to each executive officer varies depending on his position. The base salary for each executive officer is the only fixed component of compensation. All other compensation, including annual cash bonuses and long-term incentive compensation, is variable in nature as it is dependent upon achievement of certain performance measures. The following table summarizes the components as percentages of each named executive officer’s total cash compensation opportunity in fiscal 2008.


			Cash		Long-Term
	Base Salary		Bonus Target		Incentive

Mark A. Alexander⁽¹⁾		43%		43%		14%
Michael A. Stivala		50%		33%		17%
Michael J. Dunn, Jr.		40%		40%		20%
Steven C. Boyd		52%		31%		17%
Michael M. Keating		50%		33%		17%


(1)		Mr. Alexander’s Long-Term Incentive Plan award is considerably less than Mr. Dunn’s per the terms of an agreement between Mr. Alexander and the Partnership.

In allocating compensation among these elements, we believe that the compensation of our senior-most levels of management—the levels of management having the greatest ability to influence our performance—should be approximately 50% performance-based, while lower levels of management should receive a greater portion of their compensation in base salary. Additionally, our short-term and long-term incentive plans do not provide for minimum payments and are, thus, truly pay-for-performance compensation plans.

Internal Pay Equity

In determining the different compensation packages for each of our named executive officers, the Committee takes into consideration a number of factors, including the level of responsibility and influence that each named executive officer has over the affairs of the Partnership, tenure, individual performance and years in one’s current position. The relative importance assigned to each of these factors by the Committee may differ from executive to executive. The Committee will also consider the existing level of equity ownership of each of our named executive officers when granting awards under our 2000 Restricted Unit Plan and the 2003 Long-Term Incentive Plan (see below for a description of both plans). The compensation packages for our Chief Executive Officer and our President are set forth in their respective employment agreements, as further described below. As a result, different weight may be given to different components of compensation among each of our named executive officers. In addition, as discussed in the section above titled “Allocation Among Components,” the compensation packages that we provide to our senior-most levels of management are, at a minimum, approximately 50% performance-based. In order to align the interests of senior management with the interests of our Common Unitholders, we consider it requisite to accentuate the performance-based elements of the compensation packages that we provide to these individuals because the actions and decisions of these individuals have a direct impact on our performance.

Base Salary

Base salaries for the named executive officers and, indeed, all of our other executive officers, are reviewed and approved annually by the Committee. In order to determine the fiscal 2008 base salary increases, the Committee compared each executive officer’s fiscal 2007 base salary with the corresponding mean salary provided in the Mercer database. The Committee determined base salary adjustments, which may be higher or lower than the comparative data, following an assessment of our overall results as well as each executive officer’s position, performance and scope of responsibility, while at the same time considering each executive officer’s previous total cash compensation opportunities. At the beginning of fiscal 2008, each named executive officer received adjustments to his base salary in accordance with the philosophy and process described above, ranging from 0% to 25%. In the event of a promotion (such as Mr. Boyd’s in fiscal 2007) or a new hire, the Committee reviews and takes action at its next meeting.

The fiscal 2008 adjustments to each named executive officer’s base salary were as follows:


Mark A. Alexander⁽¹⁾	0	%
Michael A. Stivala⁽²⁾	25	%
Michael J. Dunn, Jr^.(3)	6	%
Steven C. Boyd	4	%
Michael M. Keating	5	%


(1)		Because Mr. Alexander’s base salary is set forth under the provisions of his employment agreement, the Committee did not adjust his base salary.

(2)		The Committee’s decision to increase Mr. Stivala’s salary by 25% was based on consideration of the increased responsibilities he assumed upon his promotion from Controller to Chief Financial Officer and the increasing complexity of the Chief Financial Officer’s responsibilities resulting from the promulgation of the Sarbanes-Oxley Act and related regulations.

(3)		Although Mr. Dunn’s initial base salary was established under the terms of his employment agreement, those terms provide for annual base salary adjustments at the discretion of the Committee.

The total base salary paid to each named executive officer in fiscal 2008 is reported in the column titled “Salary ($)” in the Summary Compensation Table below.

Annual Cash Bonus Plan

Annual cash bonuses (which fall within the SEC’s definition of “Non-Equity Incentive Plan Compensation” for the purposes of the Summary Compensation Table and otherwise) are earned by our executive officers in accordance with the performance objective provisions of our annual cash bonus plan. The cash bonuses earned by Mr. Alexander and Mr. Dunn are the only exceptions to this general rule because their bonus provisions are established in their respective employment agreements. Although this plan is generally administered using the formula described below, occasionally the Committee may exercise its broad discretionary powers to decrease or increase the annual cash bonus paid to a particular executive officer when the Committee recognizes that a particular executive officer’s performance warrants a decreased or an increased bonus. Such adjustments, if any, are recommended to the Committee by our Chief Executive Officer. During fiscal 2008, our Chief Executive Officer did not make any such recommendations to the Committee.

The terms of our annual cash bonus plan provide for cash payments of a specified percentage (which, in fiscal 2008 ranged from 60% to 100%) of our named executive officers’ annual base salaries (“target cash bonus”) if, for the fiscal year, actual EBITDA (as defined in Item 6, herein) equals the Partnership’s budgeted EBITDA. For purposes of calculating the annual cash bonus, the Committee may exercise discretion to adjust both budgeted and actual EBITDA for various items considered to be non-recurring in nature; including, but not limited to, unrealized (non-cash) gains or losses on derivative instruments reported within cost of products sold in our statement of operations and gains or losses on the disposal of discontinued operations (“cash bonus plan EBITDA”). Executive officers have the opportunity to earn between 90% and 110% of their target cash bonuses, in accordance with the terms of the plan, paralleling the percentage of actual cash bonus plan EBITDA in relationship to budgeted cash bonus plan EBITDA ranging from 90% to 110%. Under the annual cash bonus plan, no bonuses are earned if actual cash bonus plan EBITDA is less than 90% of budgeted cash bonus plan EBITDA and cash bonuses cannot exceed 110% of the target cash bonus even if actual cash bonus plan EBITDA is more than 110% of budgeted cash bonus plan EBITDA.

For fiscal 2008, our budgeted cash bonus plan EBITDA was $187.0 million. Our actual cash bonus plan EBITDA was such that each of our executive officers earned 95% of his target cash bonus. The following table provides the fiscal 2008 budgeted cash bonus plan EBITDA targets that were established at the October 31, 2007 Compensation Committee meeting:


	Target Bonus Percentage that
	would have been Earned if
	Actual Cash Bonus Plan
Fiscal 2008 Budgeted Cash Bonus Plan EBITDA	EBITDA Equaled the Figure
(in Millions)	in the Previous Column
$205.7		110	%
$196.4		105	%
$187.0 ⁽¹⁾		100	%
$177.7		95	%
$168.3		90	%


(1)		Budgeted cash bonus plan EBITDA for fiscal 2008.

The bonuses earned under the annual cash bonus plan by each of our named executive officers are reported in the column titled “Non-Equity Incentive Plan Compensation ($)” in the Summary Compensation Table below.

The 2008 target cash bonus percentages and target cash bonuses established for each named executive officer and the actual cash bonuses earned by each of them during fiscal 2008 are summarized as follows:


	2008 Target Cash
	Bonus as a % of		2008 Target Cash		2008 Actual Cash
Name	Base Salary		Bonus		Bonus Earned
Mark A. Alexander⁽¹⁾		100%	$	450,000	$	427,500
Michael A. Stivala		65%	$	162,500	$	154,375
Michael J. Dunn, Jr.⁽¹⁾		100%	$	425,000	$	403,750
Steven C. Boyd		60%	$	147,000	$	139,650
Michael M. Keating		65%	$	143,000	$	135,850


(1)		Mr. Alexander’s and Mr. Dunn’s target cash bonuses are established by the terms of their respective employment agreements. See “Employment Agreements” section below.

For purposes of establishing the cash bonus targets for fiscal 2008, at its meeting on October 31, 2007 the Committee reviewed and approved our fiscal 2008 budgeted cash bonus plan EBITDA. The budgeted cash bonus plan EBITDA is developed annually using a bottom-up process factoring in reasonable growth targets from the prior year performance, while at the same time attempting to reach a good balance between a target that is reasonably achievable, yet not assured. As described above, executive officers will have the opportunity to earn between 90% and 110% of their target cash bonuses, paralleling the percentage of actual cash bonus plan EBITDA in relationship to budgeted cash bonus plan EBITDA ranging from 90% to 110%. Over the past three years, our actual cash bonus plan EBITDA was such that each of our executive officers earned 95%, 110% and 109% of their respective target cash bonus for fiscal 2008, 2007 and 2006, respectively.

2003 Long-Term Incentive Plan

At the beginning of fiscal 2003, we adopted the 2003 Long-Term Incentive Plan (“LTIP-2”), a phantom unit plan, as a principal component of our executive compensation program. While the annual cash bonus plan is a pay-for-performance plan that focuses on our short-term financial goals, LTIP-2 is designed to motivate our executive officers to focus on long-term financial goals. LTIP-2 measures the market performance of our Common Units on the basis of total return to our Unitholders (“TRU”) during a three-year measurement period commencing on the first day of the fiscal year in which an unvested award was granted and compares our TRU to the TRU of each of the other members of a predetermined peer group, consisting solely of other master limited partnerships, approved by the Committee. The predetermined peer group may vary from year-to-year, but for all current awards, includes AmeriGas Partners, L.P., Ferrellgas Partners, L.P. and Inergy, L.P. (the other propane master limited partnerships). Unvested awards are granted at the beginning of each fiscal year as a Committee-approved percentage of each executive officer’s salary. Cash payouts, if any, are earned and paid at the end of the three-year measurement period.

LTIP-2 is designed to:

	•		Align a portion of our executive officers’ compensation opportunities with the long-term goals of our Unitholders;

	•		Provide long-term compensation opportunities consistent with market practice;

	•		Reward long-term value creation; and

	•		Provide a retention incentive for our executive officers and other key employees.

At the beginning of the three-year measurement period, each executive officer’s unvested grant of phantom units is calculated by dividing a predetermined percentage (which is 30% for Mr. Alexander and for all other executive officers is 52%), established upon adoption of LTIP-2, of the executive officer’s target cash bonus by the average of the closing prices of our Common Units for the twenty days preceding the beginning of the fiscal year. At the end of the three-year measurement period, depending on the quartile ranking within which our TRU falls relative to the other members of the peer group, our executive officers, as well as the other participants, all of whom are key employees, will receive a cash payout equal to:

	•		The quantity of the participant’s phantom units multiplied by the average of the closing prices of our Common Units for the twenty days preceding the conclusion of the three-year measurement period;

	•		The quantity of the participant’s phantom units multiplied by the sum of the distributions that would have inured to one of our outstanding Common Units during the three-year measurement period; and

	•		The sum of the products of the two preceding calculations multiplied by: zero if our performance falls within the lowest quartile of the peer group; 50% if our performance falls within the second lowest quartile; 100% if our performance falls within the second highest quartile; and 125% if our performance falls within the top quartile.

The three-year measurement period of the fiscal 2006 award ended simultaneously with the conclusion of fiscal 2008. The TRU for the fiscal 2006 award fell within the highest quartile. The following is a summary of the cash payouts related to the fiscal 2006 award earned by our named executive officers at the conclusion of fiscal 2008.


Mark A. Alexander	$	239,740	⁽¹⁾
Michael A. Stivala	$	81,526	⁽¹⁾
Michael J. Dunn, Jr.	$	346,263	⁽¹⁾
Steven C. Boyd	$	91,107	⁽¹⁾
Michael M. Keating	$	115,864	⁽¹⁾


(1)		The cash payouts related to our named executive officers’ fiscal 2006 awards earned at the conclusion of fiscal 2008 is an additional disclosure that bears no meaningful relationship to the SFAS 123R expense recognized during fiscal 2008 and reported in column (e) of the Summary Compensation Table below.

The following is a summary of the quantity of phantom units that signify the unvested grants to our named executive officers during fiscal years 2007 and 2008 that will be used to calculate cash payments at the end of each respective award’s three-year measurement period (i.e., at the end of our fiscal year 2009 for the fiscal 2007 award and at the end of our fiscal year 2010 for the fiscal 2008 award).


	Fiscal Year		Fiscal Year
	2007 Award		2008 Award
Mark A. Alexander		4,007		2,989
Michael A. Stivala		1,603		1,871
Michael J. Dunn, Jr.		6,174		4,894
Steven C. Boyd		2,037		1,693
Michael M. Keating		2,107		1,647

The peer group members selected by the Committee for the fiscal 2007 and fiscal 2008 awards consist entirely of publicly-traded partnerships, inclusive of all propane-related partnerships. The Committee decided upon this peer group because all publicly-traded partnerships have similar tax attributes and can, as a result, distribute more cash than similarly-sized corporations generating similar revenues. The following table lists, in alphabetical order, the names and ticker symbols of the peer group used to measure our performance during the fiscal 2007 and fiscal 2008 LTIP-2 awards’ three-year measurement periods:

2007 and 2008 LTIP-2 Awards Peer Group


Peer Group Member Name		Ticker Symbol
AmeriGas Partners, L.P.		APU
Copano Energy, LLC		CPNO
Crosstex Energy, L.P.		XTEX
Dorchester Minerals, L.P.		DMLP
Energy Transfer Partners, L.P.		ETP
Ferrellgas Partners, L.P.		FGP
Inergy, L.P.		NRGY
MarkWest Energy Partners, L.P.		MWE
Plains All American Pipeline, L.P.		PAA
Star Gas Partners, L.P.		SGU
Sunoco Logistics Partners, L.P.		SXL

Formerly, the LTIP-2 plan document contained a retirement provision that provided for the immediate termination of the three-year measurement period for all outstanding LTIP-2 awards held by a retirement-eligible participant upon retirement. Under the former provisions, TRU was calculated as if the three-year measurement period for each outstanding award ended on the participant’s retirement date in order to determine whether a payment had been earned by the retiree. On January 24, 2008, the Committee amended the retirement provisions of the plan document to provide that a retirement-eligible participant’s outstanding awards vest as of the retirement-eligible date, but such awards remain subject to the same three-year measurement period for purposes of determining the eventual cash payout, if any, at the conclusion of the measurement period.

Because the cash payments under the LTIP-2 are based on the value of our Common Units, compensation expense generated by this plan is recognized in accordance with SFAS 123R. As a result, all such charges to this year’s earnings relative to our named executive officers are reported in the column titled “Unit Awards ($)” in the Summary Compensation Table below.

2000 Restricted Unit Plan

We adopted the 2000 Restricted Unit Plan (“RUP”) effective November 1, 2000. Upon adoption, this plan authorized the issuance of 487,805 Common Units to our executive officers, managers and other employees and to the members of our Board of Supervisors. On October 17, 2006, following approval by our Unitholders, we adopted amendments to the RUP which, among other things, increased the number of Common Units authorized for issuance under the RUP by 230,000 for a total of 717,805. At the conclusion of fiscal 2008, there remained 89,874 restricted units available for future grants.

When the Committee authorizes a grant of restricted units, the unvested units underlying a grant do not provide the grantee with voting rights and do not receive distributions or accrue rights to distributions during the vesting period. Restricted unit grants vest as follows: 25% on each of the third and fourth anniversaries of the grant date and the remaining 50% on the fifth anniversary of the grant date. Unvested grants are subject to forfeiture in certain circumstances as defined in the RUP document. Upon vesting, restricted units are automatically converted into our Common Units, with full voting rights and rights to receive distributions.

The RUP document previously contained a retirement provision that provided for the immediate vesting of all unvested RUP grants held by a retiring participant who met all three of the following conditions on his or her retirement date:

	1.		The unvested RUP grant has been held by the grantee for at least six months;

	2.		The RUP grantee is age 55 or older; and

	3.		The RUP grantee has worked for us or one of our predecessors for at least 10 years.

On October 31, 2007, in order to comply with the regulations promulgated under Internal Revenue Code (“IRC”) Section 409A, the Board of Supervisors amended the retirement provision to require a six-month delay between a retirement eligible RUP participant’s retirement date and the date on which unvested RUP grants vest.

All RUP grants are made at the discretion of the Committee. Because individual circumstances differ, the Committee has not adopted a formulaic approach to making RUP grants. Grants are awarded at the Committee’s discretion when the need arises. Although the reasons for awarding a grant can vary, the objective of awarding a grant to a recipient is twofold: to retain the services of the recipient over the five-year vesting period while, at the same time providing the type of motivation that further aligns the long-term interests of the recipient with the long-term interests of our Unitholders. The reasons for which the Committee awards RUP grants include, but are not limited to, the following:

•

To attract skilled and capable candidates to fill vacant positions;

•

To retain the services of an employee;

•

To provide an adequate compensation package to accompany an internal promotion; and

•

To reward outstanding performance.

In determining the quantity of restricted units to award to each executive officer and other key employees, the Committee considers, without limitation:

•

The executive officer’s scope of responsibility, performance and contribution to meeting our objectives;

•

The total cash compensation opportunity provided to the executive officer for whom the grant is being considered;

•

The value of similar equity awards to executive officers of similarly sized enterprises; and

•

The current value of a similar quantity of outstanding Common Units.

In addition, in establishing the level of restricted units to grant to our executive officers, the Committee considers the existing level of equity ownership by our executive officers and, prior to October 17, 2006, the level of equity representation through management’s ownership of the then General Partner.

When the Committee decides to grant an equity award, it approves a dollar amount of equity compensation that it wants to provide to a particular employee. This dollar amount is then converted into a quantity of restricted units by dividing that dollar amount by the average of the closing prices of our Common Units for the twenty trading days preceding the grant date. The Committee generally makes these awards at their first meeting each year following the availability of the financial results for the prior fiscal year; however, occasionally the Committee grants awards at other times of the year, particularly when the need arises to grant awards because of promotions and new hires.

Until October 17, 2007, the grant date for RUP grants usually coincided with the Committee’s approval date. However, on October 31, 2007, the Committee adopted a policy with respect to the effective date of subsequent grants of restricted units under the RUP which states that:

Unless the Committee expressly determines otherwise for a particular award at the time of its approval of such award, the effective date of grant of all awards of restricted units under the RUP in a given calendar year will be the first business day in the month of December of that calendar year. If, at the discretion of the Committee, an award is expressed as a dollar amount, then such award will be converted into the number of restricted units, as of the effective date of grant, obtained by dividing the dollar amount of the award by the average of the closing prices, on the New York Stock Exchange, of one Common Unit of the Partnership for the 20 trading days immediately prior to that effective date of grant.

During fiscal 2008, RUP grants were awarded to the following named executive officers:


	Grant Date	Quantity of Restricted Units

Michael A. Stivala	December 3, 2007		2,272
Michael J. Dunn, Jr.	December 3, 2007		29,533
Steven C. Boyd	December 3, 2007		3,408
Michael M. Keating	December 3, 2007		3,408

All fiscal 2008 awards were made in recognition of the exemplary performance of each of the recipients and as retention tools. The quantity of units selected for Mr. Dunn’s award was considerably higher than the quantities granted to the other recipients in recognition of his responsibilities as President and in consideration of his not receiving any prior grants under the RUP, unlike each of the other named executive officers. Additionally, the Committee relied upon information provided by Mercer to conclude that this grant and all of the other grants were necessary to remediate shortfalls perceived by the Committee in the cash compensation of each of the named executive officers. Additionally, the Committee believed that each of these grants will function as a necessary retention tool. To that end, although Mr. Dunn currently satisfies the criteria found in the retirement provisions of the RUP document, the Committee exercised its discretionary authority to make his award subject to the special stipulation that he hold his unvested award for three years before the retirement provisions of the RUP document become applicable.

Compensation expense for unvested RUP grants is recognized ratably over the vesting periods and is net of estimated forfeitures in accordance with SFAS 123R. The RUP-related SFAS 123R expense recognized in the Partnership’s fiscal 2008 statement of operations, excluding forfeiture estimates, on behalf of each of the named executive officers is reported in the column titled “Unit Awards ($)” in the Summary Compensation Table below.

Recoupment of Incentive Compensation

On April 25, 2007, upon recommendation by the Committee, the Board of Supervisors approved an Incentive Compensation Recoupment Policy which permits the Committee to seek the reimbursement from certain executives of the Partnership and Operating Partnership of incentive compensation paid to those executives in connection with any fiscal year for which there is a significant restatement of the published financial statements of the Partnership triggered by a material accounting error, which results in less favorable results than those originally reported by the Partnership. Such reimbursement can be sought from executives even if they had no responsibility for the restatement. In addition to the foregoing, if the Committee determines that any fraud or intentional misconduct by an executive was a contributing factor to the Partnership having to make a significant restatement, then the Committee is authorized to take appropriate action against such executive, including disciplinary action, up to, and including, termination, and requiring reimbursement of all, or any part, of the compensation paid to that executive in excess of that executive’s base salary, including cancellation of any unvested restricted units. The Incentive Compensation Recoupment Policy is available on our website at www.suburbanpropane.com.

On July 31, 2007, the Board amended the annual cash bonus plan, LTIP-2 and the RUP to expressly make future awards under such plans subject to the Incentive Compensation Recoupment Policy.

Pension Plan

We sponsor a noncontributory defined benefit pension plan that was originally designed to cover all of our eligible employees who met certain criteria relative to age and length of service. Effective January 1, 1998, we amended the plan in order to provide for a cash balance format rather than the final average pay format that was in effect prior to January 1, 1998. The cash balance format is designed to evenly spread the growth of a participant’s earned retirement benefit throughout his or her career rather than the final average pay format, under which a greater portion of a participant’s benefits were earned toward the latter stages of his or her career. Effective January 1, 2000, we amended the plan to limit participation in this plan to existing participants and no longer admit new participants to the plan. On January 1, 2003, we amended the plan to cease future service and pay-based credits on behalf of the participants and, from that point on, participants’ benefits have increased only due to interest credits.

Each of our named executive officers, with the exception of Mr. Stivala, participates in the plan. The changes in the actuarial value relative to each named executive officer’s participation in the plan is reported in the column titled “Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)” in the Summary Compensation Table below.

Deferred Compensation

All employees, including the named executive officers, who satisfy certain service requirements, are entitled to participate in our IRC Section 401(k) Plan (the “401(k) Plan”), in which participants may defer a portion of their eligible cash compensation up to the limits established by law. We offer the 401(k) Plan to attract and retain talented employees by providing them with a tax-advantaged opportunity to save for retirement.

For fiscal 2008, all of our named executive officers participated in the 401(k) Plan. The benefits provided to our named executive officers under the 401(k) Plan are provided on the same basis as to our other exempt employees. Amounts deferred by our named executive officers under the 401(k) Plan are included in the column titled “Salary ($)” in the Summary Compensation Table below.

In order to be competitive with other employers, if certain performance criteria are met, we will match our employee-participants’ contributions up to 6% of their base salary, at a rate determined based on a performance-based scale. The following chart shows the performance target criteria that must be met for each level of matching contribution:


If We Meet This		The Participating Employee
Percentage of		Will Receive this Matching
Budgeted EBITDA⁽¹⁾		Contribution for the Year

115% or higher		100%
100% to 114%		50%
90% to 99%		25%
Less than 90%		0%


(1)		For additional information regarding the non-GAAP term “Budgeted EBITDA,” refer to the explanation provided under the subheading “Annual Cash Bonus Plan” above.

For fiscal 2008, our budgeted 401(k) Plan EBITDA was $187.0 million. Similar to our annual cash bonus plan, our fiscal 2008 results were such that actual 401(k) Plan EBITDA equaled 95% of budgeted 401(k) Plan EBITDA. As a result, we will provide participants with a match equal to 25% of their calendar year 2008 contributions that did not exceed 6% of their total base pay up to a maximum base pay of $230,000. The matching contributions that we will make on behalf of our named executive officers are reported in the column titled “All Other Compensation ($)” in the Summary Compensation Table below.

Non-Qualified Deferred Compensation

Until January 2008, we maintained a Non-Qualified Deferred Compensation Plan (the “Compensation Deferral Plan”) to which vested restricted units from the 1996 Restricted Unit Plan (which was subsequently replaced by the 2000 Restricted Unit Plan described above) were deferred by the recipients, some of whom are our named executive officers, on May 26, 1999 in connection with our Recapitalization. The Compensation Deferral Plan operated through a rabbi trust, which held the deferred restricted units. On November 2, 2005, for the purpose of IRC Section 409A compliance, our Board of Supervisors approved an amendment to the Compensation Deferral Plan that prohibited any additional deferral elections.

At the end of fiscal 2007, Mr. Alexander and Mr. Dunn were the only remaining beneficiaries of the Compensation Deferral Plan. In accordance with their deferral elections, the entire corpus of the rabbi trust was distributed to them during January 2008 and the fair market value of their respective portions of the corpus is included in their taxable wage earnings for calendar year 2008.

Because the Compensation Deferral Plan contained only Common Units, and because the cash distributions that inured to those units were immediately distributed to the beneficiaries, the plan did not provide Mr. Alexander and Mr. Dunn with above market interest; nor did they receive distributions on the Common Units at a rate higher than the distributions paid on behalf of our Common Units held by the investing public. As a result, nothing relative to the Compensation Deferral Plan is reported in the Summary Compensation Table below.

Supplemental Executive Retirement Plan

In 1998, we adopted a non-qualified, unfunded supplemental retirement plan known as the Suburban Propane Company Supplemental Executive Retirement Plan (the “SERP”). The purpose of the SERP is to provide Mr. Alexander and Mr. Dunn with a level of retirement income from us, without regard to statutory maximums, including the IRC’s limitation for defined benefit plans. In light of the conversion of the Pension Plan to a cash balance formula as described under the subheading “Pension Plan” above, the SERP was amended and restated effective January 1, 1998. The annual retirement benefit under the SERP represents the amount of annual benefits that the participants in the SERP would otherwise be eligible to receive, calculated using the same pay-based credits referenced in the “Pension Plan” section above, applied to the amount of annual compensation that exceeds the IRC’s statutory maximums for defined benefit plans, which was $200,000 in 2002. Effective January 1, 2003, the SERP was discontinued with a frozen benefit determined for Mr. Alexander and Mr. Dunn. Provided that the SERP requirements are met, upon retirement Mr. Alexander will receive a monthly benefit of $6,737 and Mr. Dunn will receive a monthly benefit of $373. Because this plan does not provide Mr. Alexander and Mr. Dunn with above market interest credits, nothing relative to the SERP is reported in the Summary Compensation Table below.

Other Benefits

As part of his total compensation package, each named executive officer is eligible to participate in all of our other employee benefit plans, such as the medical, dental, group life insurance and disability plans. In each case, with the exception of Mr. Alexander for whom we purchase supplemental life insurance and supplemental long-term disability policies at a cost of $6,693 per year, these benefits are provided on the same basis as are provided to other exempt employees. These benefit plans are offered to attract and retain talented employees and to provide them with competitive benefits.

Other than to Mr. Alexander and Mr. Dunn, in accordance with the terms of their employment agreements (described below), there are no post-termination or other special rights provided to any named executive officer to participate in these benefit programs other than the right to participate in such plans for a fixed period of time following termination of employment, on the same basis as is provided to other exempt employees, as required by law.

The costs of all such benefits incurred on behalf of our named executive officers are reported in the column titled “All Other Compensation ($)” in the Summary Compensation Table below.

Perquisites

Perquisites represent a minor component of our executive officers’ compensation. Each of the named executive officers is eligible for tax preparation services, a company-provided vehicle, and an annual physical. The following table summarizes both the value and the utilization of these perquisites by the named executive officers in fiscal 2008.


			Employer-
	Tax Preparation		Provided
Name	Services		Vehicle		Physical
Mark A. Alexander	$	5,000	$	11,395	$	1,500
Michael A. Stivala	$	-0-	$	12,647	$	1,500
Michael J. Dunn, Jr.	$	2,500	$	12,888	$	1,500
Steven C. Boyd	$	900	$	6,549	$	-0-
Michael M. Keating	$	2,500	$	11,522	$	1,200

Perquisite-related costs are reported in the column titled “All Other Compensation ($)” in the Summary Compensation Table below.

Impact of Accounting and Tax Treatments of Executive Compensation

As we are a partnership and not a corporation for federal income tax purposes, we are not subject to the limitations of IRC Section 162(m) with respect to tax deductible executive compensation. Accordingly, none of the compensation paid to our named executive officers is subject to a limitation as to tax deductibility. However, if such tax laws related to executive compensation change in the future, the Committee will consider the implications on us.

In accordance with their respective employment agreements, Mr. Alexander and Mr. Dunn are entitled to receive tax gross-up payments for any parachute excise tax incurred pursuant to IRC Section 4999; they are also entitled to receive tax gross-up payments for any payment that violates the provisions of IRC Section 409A or its associated regulations.

On November 2, 2005, the Board of Supervisors approved an amendment to the Suburban Propane, L.P. Severance Protection Plan for Key Employees (the “Severance Plan”) to provide that if any payment under the Severance Plan subjects a participant to the 20% federal excise tax under IRC Section 409A, the payment will be grossed up to permit such participant to retain a net amount on an after-tax basis equal to what he or she would have received had the excise tax not been payable.

Employment Agreements

Mr. Alexander, our Chief Executive Officer, and Mr. Dunn, our President, are the only named executive officers, named or otherwise, with whom we have employment agreements. We entered into an employment agreement with Mr. Alexander when it was announced, on March 5, 1996, that he would become our Chief Executive Officer. This agreement was subsequently amended on October 23, 1997, April 14, 1999 and November 2, 2005. We entered into an employment agreement that had an effective date of February 1, 2007 with Mr. Dunn on February 5, 2007. On November 13, 2008, the Committee approved an amendment to each of Mr. Alexander’s and Mr. Dunn’s employment agreements to bring these agreements into conformance with the final regulations issued by the IRS under IRC Section 409A, which amendments were then executed by the Company and these executives. These amendments did not effect any substantive changes to the benefits received by these executives under the agreements.

Mr. Alexander’s Employment Agreement had an initial term of three years, and automatically renews for successive one-year periods, unless earlier terminated by us or by Mr. Alexander or otherwise terminated in accordance with the terms of the employment agreement. The employment agreement provides for an annual base salary of $450,000 and provides Mr. Alexander with the opportunity to earn a cash bonus of up to 100% of base salary based upon the achievement of the same EBITDA-related performance criteria as contained in our annual cash bonus plan described in the section titled “Annual Cash Bonus Plan” above. Under our Partnership Agreement, the Committee has the authority to grant Mr. Alexander a bonus in excess of 100% if, in accordance with the terms of the annual cash bonus plan, our other executive officers earn bonuses exceeding their target bonuses for the fiscal year. The Committee exercised this authority in connection with Mr. Alexander’s cash bonus for fiscal 2006 and fiscal 2007. The discretionary component of Mr. Alexander’s fiscal 2007 cash bonus is disclosed in the column titled “Bonus ($)” and the non-discretionary component of Mr. Alexander’s bonus is disclosed in the column titled “Non-Equity Incentive Plan Compensation ($)” in the Summary Compensation Table below.

The final provisions of both employment agreements were the results of negotiations between the Committee and each individual and are not reducible to a specific process. For example, Mr. Alexander is the only Chief Executive Officer that has been employed by the Partnership. As a result, some aspects of his employment arrangements predate the existence of the Partnership and were agreed to by the former general partner. Over the years, when considering whether to renew Mr. Alexander’s contract, the Committee has considered, among other factors, Mr. Alexander’s experience, performance and the fact that our headquarters are located in the New York Metropolitan area. Similar considerations applied to the circumstances under which Mr. Dunn’s employment agreement was negotiated. The Partnership’s termination and change of control arrangements are an important part of the competitive total compensation provided to its executives. These termination and change of control arrangements also assist in retaining those executives with leadership abilities and skills necessary during a transition period. These arrangements did not affect any decision made in fiscal 2008 with respect to any other compensation elements for our named executive officers.

Mr. Alexander’s employment agreement also provides for the opportunity to participate in benefit plans made available to our other executive officers and our other key employees. We also provide Mr. Alexander with a term life insurance policy with a face amount equal to three times his base salary.

If a change of control (as defined in the “Change of Control” section below) of the Partnership occurs, and within six months prior thereto or at any time subsequent to such change of control, we terminate Mr. Alexander’s employment without cause (as defined in the “Severance Benefits” section below) or if Mr. Alexander resigns with good reason (as defined in the “Severance Benefits” section below) or terminates his employment commencing on the six month anniversary and ending on the twelve month anniversary of such change of control, then Mr. Alexander shall be entitled to:

•

A lump sum severance payment equal to three times his annual base salary in effect as of the date of termination plus three times his annual cash bonus at 100%; and

•

Medical benefits for three years from the date of such termination.

In situations unconnected to a change of control event, if the Partnership terminates Mr. Alexander’s employment without cause or if Mr. Alexander resigns with good reason, then Mr. Alexander shall be entitled to:

•

A severance payment equal to (A) the portion of his base salary earned but not paid as of the date of termination, (B) his pro-rata annual cash bonus under the employment agreement based upon the number of days worked during the fiscal year of termination, and (C) three times his annual base salary in effect as of the date of termination; and

•

Medical benefits for three years from the date of such termination reduced to the extent comparable benefits are provided to Mr. Alexander by another party.

The employment agreement requires that if any payment received by Mr. Alexander is subject to the 20% excise tax under IRC Section 4999, the payment shall be increased to permit Mr. Alexander to retain a net amount on an after-tax basis equal to what he would have received had the excise tax not been payable.

If Mr. Alexander’s employment is terminated due to death, disability, without good reason, or pursuant to delivery of a non-renewal notice to the Partnership in accordance with the terms and conditions of his employment agreement, he or his estate, as the case may be, shall be entitled to earned but unpaid base salary plus his pro-rata cash bonus. If his employment is terminated by the Partnership for cause, he shall be entitled to his earned but unpaid base salary only.

Mr. Dunn’s employment agreement has an initial term of two years commencing on February 1, 2007, the term of which shall automatically renew for successive one-year periods, unless earlier terminated by us or by Mr. Dunn or otherwise terminated in accordance with the terms of the employment agreement. The provisions of Mr. Dunn’s employment agreement provided for an initial annual base salary of $400,000 per year (which may be adjusted upwards annually at the Committee’s discretion) and, in accordance with the provisions of our annual cash bonus plan, the opportunity to earn a cash bonus in each fiscal year up to 110% of his annual base salary for that same fiscal year (the “Maximum Annual Cash Bonus”). Additionally, Mr. Dunn’s employment agreement permits him to participate in the same benefit plans made available to our other executive officers and other key employees.

If a change of control (as defined in the “Change of Control” section below) of the Partnership occurs and within six months prior thereto or within two years thereafter the Partnership terminates Mr. Dunn’s employment without cause (as defined in the “Severance Benefits” section below) or if Mr. Dunn resigns with good reason (as defined in the “Severance Benefits” section below), then Mr. Dunn shall be entitled to a severance payment equal to the sum of:

•

The portion of his base salary earned but not paid as of the date of termination;

•

His pro-rata cash bonus (the bonus Mr. Dunn would have been entitled to under the employment agreement for the full fiscal year in which the termination occurred multiplied by the number of days from the beginning of that fiscal year until the termination date and divided by 365);

•

Two times the sum of (1) his annual base salary in effect as of the date of termination, plus (2) the Maximum Annual Cash Bonus; and

•

Medical benefits for two years from the date of such termination.

In situations unconnected to a change of control event, if the Partnership terminates Mr. Dunn’s employment without cause, or if Mr. Dunn resigns with good reason, then Mr. Dunn shall be entitled to:

•

A severance payment equal to (A) the portion of his base salary earned but not paid as of the date of termination, (B) the annual cash bonus Mr. Dunn would have been entitled to under the employment agreement for the full fiscal year in which the termination occurred had Mr. Dunn remained employed by the Partnership for that full fiscal year, and (C) two times his annual base salary in effect as of the date of termination; and

•

Medical benefits for two years from the date of such termination.

The employment agreement requires that if any payment received by Mr. Dunn is subject to the 20% excise tax under IRC Section 4999, the payment shall be increased to permit Mr. Dunn to retain a net amount on an after-tax basis equal to what he would have received had the excise tax not been payable.

If Mr. Dunn’s employment is terminated due to death, disability, or pursuant to delivery of a non-renewal notice to the Partnership in accordance with the terms and conditions of his employment agreement, he or his estate, as the case may be, shall be entitled to earned but unpaid base salary plus his pro-rata cash bonus for the fiscal year during which termination occurred. If his employment is terminated by the Partnership for cause, or he resigns without good reason, he shall be entitled to his earned but unpaid base salary only.

For additional information, see the table titled “Potential Payments Upon Termination” below.

Severance Benefits

We believe that, in most cases, employees should be paid reasonable severance benefits. Therefore, it is the general policy of the Committee to provide executive officers and other key employees who are terminated by us without cause or who choose to terminate their employment with us for good reason with a severance payment equal to, at a minimum, one year’s base salary, unless circumstances dictate otherwise. This policy was adopted because it may be difficult for former executive officers and other key employees to find comparable employment within a short period of time. However, depending upon individual facts and circumstances, particularly the severed employee’s tenure with us, the Committee may make exceptions to this general policy.

A “key employee” is an employee who has attained a director level pay-grade or higher. “Cause” will be deemed to exist where the individual has been convicted of a crime involving moral turpitude, has stolen from us, has violated his or her non-competition or confidentiality obligations, or has been grossly negligent in fulfillment of his or her responsibilities. “Good reason” generally will exist where an executive officer’s position or compensation has been decreased or where the employee has been required to relocate.

Change of Control

Our executive officers and other key employees have built the Partnership into the successful enterprise that it is today; therefore, we believe that it is important to protect them in the event of a change of control. Further, it is our belief that the interests of our Unitholders will be best served if the interests of our executive officers are aligned with them, and that providing change of control benefits should eliminate, or at least reduce, the reluctance of our executive officers to pursue potential change of control transactions that may be in the best interests of our Unitholders. Additionally, we believe that the severance benefits provided to our executive officers and to our key employees are consistent with market practice and appropriate because these benefits are an inducement to accepting employment and because the executive officers have agreed to and are subject to non-competition and non-solicitation covenants for a period following termination of employment. Therefore, our executive officers and other key employees are provided with employment protection following a change of control (the “Severance Protection Plan”). Our Severance Protection Plan covers all executive officers, including the named executive officers, with the exception of our Chief Executive Officer and our President, whose severance provisions are established in their respective employment agreements.

The Severance Protection Plan provides for severance payments of either sixty-five or seventy-eight weeks of base salary and target cash bonuses for such officers and key employees following a change of control and termination of employment. All named executive officers who participate in the Severance Protection Plan are eligible for seventy-eight weeks of base salary and target bonuses. Relative to the overall value of the Partnership, these potential change of control benefits are relatively minor. The cash components of any change of control benefits are paid in a lump sum.

In addition, upon a change of control, without regard to whether a participant’s employment is terminated, all unvested awards granted under the RUP will vest immediately and become distributable to the participants and all outstanding, unvested LTIP-2 grants will vest immediately as if the three-year measurement period for each outstanding grant concluded on the date the change of control occurred and our TRU was such that, in relation to the performance of the other members of the peer group, it fell within the top quartile.

For purposes of these benefits, a change of control is deemed to occur, in general, if:

•

An acquisition of our Common Units or voting equity interests by any person immediately after which such person beneficially owns more than 30% of the combined voting power of our then outstanding Common Units, unless such acquisition was made by (a) us or our subsidiaries, Suburban Energy Services Group, LLC, or any employee benefit plan maintained by us, our Operating Partnership or any of our subsidiaries, or (b) any person in a transaction where (A) the existing holders prior to the transaction own at least 50% of the voting power of the entity surviving the transaction and (B) none of the Unitholders other than the Partnership, our subsidiaries, any employee benefit plan maintained by us, our Operating Partnership, or the surviving entity, or the existing beneficial owner of more than 25% of the outstanding Common Units owns more than 25% of the combined voting power of the surviving entity (such transaction, a “Non-Control Transaction”); or

•

Approval by our partners of (a) a merger, consolidation or reorganization involving the Partnership other than a Non-Control Transaction; (b) a complete liquidation or dissolution of the Partnership; or (c) the sale or other disposition of 40% or more of the gross fair market value of all the assets of the Partnership to any person (other than a transfer to a subsidiary).

The SERP (as discussed above in the section titled “Supplemental Executive Retirement Plan”) will terminate effective on the close of business thirty days following the change of control. Mr. Alexander and Mr. Dunn will be deemed to have retired and will have their respective benefits determined as of the date the plan is terminated with payment of their benefits no later than ninety days after the change of control. Each will receive a lump sum payment equivalent to the present value of his benefit payable under the plan utilizing the lesser of the prime rate of interest as published in the Wall Street Journal as of the date of the change of control or one percent, as the discount rate to determine the present value of the accrued benefit.

For purposes of the SERP, a change of control is deemed to occur, in general, if:

•

An acquisition of our Common Units or voting equity interests by any person immediately after which such person beneficially owns more than 25% of the combined voting power of our then outstanding Common Units, unless such acquisition was made by (a) us or our subsidiaries, Suburban Energy Services Group, LLC, or any employee benefit plan maintained by us, our Operating Partnership or any of our subsidiaries, or (b) any person in a transaction where (A) the existing holders prior to the transaction own at least 60% of the voting power of the entity surviving the transaction and (B) none of the Unitholders other than the Partnership, our subsidiaries, any employee benefit plan maintained by us, our Operating Partnership, or the surviving entity, or the existing beneficial owner of more than 25% of the outstanding Common Units owns more than 25% of the combined voting power of the surviving entity (such transaction, a “Non-Control Transaction”); or

•

Approval by our partners of (a) a merger, consolidation or reorganization involving the Partnership other than a Non-Control Transaction; (b) a complete liquidation or dissolution of the Partnership; or (c) the sale or other disposition of 50% or more of our net assets to any person (other than a transfer to a subsidiary).

For additional information pertaining to severance payable to our named executive officers following a change of control-related termination, see the tables titled “Potential Payments Upon Termination” below.

Report of the Compensation Committee

The Compensation Committee has reviewed and discussed with management this Compensation Discussion and Analysis. Based on its review and discussions with management, the Committee recommended to the Board of Supervisors that this Compensation Discussion and Analysis be included in this Annual Report on Form 10-K for fiscal 2008.

The Compensation Committee:

John Hoyt Stookey, Chairman
John D. Collins
Harold R. Logan, Jr.
Dudley C. Mecum
Jane Swift

ADDITIONAL INFORMATION REGARDING EXECUTIVE COMPENSATION

Summary Compensation Table for Fiscal 2008

The following table sets forth certain information concerning compensation of each named executive officer during the fiscal years ended September 27, 2008 and September 29, 2007:


											Change in
											Pension Value
											and
											Nonqualified
									Non-Equity		Deferred
							Unit		Incentive Plan		Compensation		All Other
Name and Principal			Salary		Bonus		Awards		Compensation		Earnings		Compensation		Total
Position	Year		($)⁽¹⁾		($)⁽²⁾		($)⁽³⁾		($)⁽⁴⁾		($)⁽⁵⁾		($)⁽⁶⁾		($)
(a)	(b)		(c )		(d)		(e)		(g)		(h)		(i)		(j)
Mark A. Alexander		2008	$	450,000		—	$	171,606	$	427,500		—	$	46,926	$	1,096,032
Chief Executive Officer		2007	$	450,000	$	45,000	$	410,238	$	456,188		—	$	52,507	$	1,413,933

Michael A. Stivala		2008	$	250,000		—	$	157,913	$	154,375		—	$	32,589	$	594,877
Chief Financial		2007	$	200,000		—	$	210,370	$	132,831		—	$	32,356	$	575,557
Officer & Chief Accounting Officer

Michael J. Dunn, Jr.		2008	$	425,000		—	$	498,395	$	403,750		—	$	38,976	$	1,366,121
President		2007	$	391,552		—	$	824,713	$	443,568	$	6,752	$	44,879	$	1,711,464

Steven C. Boyd		2008	$	245,000		—	$	178,116	$	139,650		—	$	26,406	$	589,172
Vice President of		2007	$	226,232		—	$	243,910	$	155,868		—	$	34,202	$	660,212
Operations

Michael M. Keating		2008	$	220,000		—	$	290,955	$	135,850		—	$	35,109	$	681,914
Vice President of		2007	$	210,000		—	$	266,908	$	151,611	$	5,648	$	43,816	$	677,983
Human Resources & Admin.


(1)		Includes amounts deferred by named executive officers as contributions to the qualified 401(k) Plan. For more information on Mr. Alexander’s and Mr. Dunn’s base salaries, refer to the subheading titled “Employment Agreements” in the “Compensation Discussion and Analysis” above. During fiscal 2007, Mr. Stivala was not our Chief Financial Officer. His promotion from Controller to Chief Financial Officer was effective on September 30, 2007; therefore, the $50,000 increase between his fiscal 2007 and fiscal 2008 base salary is attributable to the increased responsibilities associated with his promotion.

		For more information on the relationship between salaries and other cash compensation (i.e., annual cash incentives and 2003 Long-Term Incentive Plan awards), refer to the subheading titled “Allocation Among Components” in the “Compensation Discussion and Analysis” above.

(2)		For fiscal 2007, during its October 31, 2007 meeting, the Committee exercised its discretionary authority to provide Mr. Alexander with an incentive payment equal to 110% of his target cash bonus to parallel the cash bonuses earned by the other named executive officers under the annual cash bonus plan. The amount reported in this column represents the additional 10% awarded to Mr. Alexander at the Committee’s discretion.

(3)		The amounts reported in this column represent the expense, before the application of forfeiture estimates, recognized in our fiscal 2008 and 2007 statements of operations with respect to RUP grants made in fiscal years 2008 and 2007, as well as in prior fiscal years, and for LTIP-2 grants made in fiscal years 2008 and 2007 as well as in prior fiscal years. The specific details regarding these plans are provided in the preceding “Compensation Discussion and Analysis” under the subheadings “2000 Restricted Unit Plan” and “2003 Long-Term Incentive Plan.” The calculations of the charges to earnings generated by both plans were made in accordance with SFAS 123R. The breakdown for each plan with respect to each named executive officer is as follows:


Plan Name	Mr. Alexander		Mr. Stivala		Mr. Dunn		Mr. Boyd		Mr. Keating
2008
RUP		N/A	$	81,983	$	309,366	$	94,480	$	160,358
LTIP-2	$	171,606		75,930		189,029		83,636		130,597

Total	$	171,606	$	157,913	$	498,395	$	178,116	$	290,955


2007
RUP		N/A	$	82,507		N/A	$	87,127	$	39,911
LTIP-2	$	410,238		127,863	$	824,713		156,783		226,997

Totals	$	410,238	$	210,370	$	824,713	$	243,910	$	266,908


		Because Mr. Dunn has met the retirement eligibility criteria under the provisions of LTIP-2, the accounting rules set forth in SFAS 123R require full recognition of all expense relative to such plans for Mr. Dunn. Although Mr. Dunn has also met the retirement eligibility criteria under the RUP’s normal retirement provisions, at the discretion of the Committee, Mr. Dunn’s unvested award must be held for three years from the grant date of December 3, 2007 before the retirement provisions become applicable. As a result, the expense associated with Mr. Dunn’s RUP award shall be recognized over this three year period.


		Mr. Dunn’s December 3, 2007 RUP award of 29,533 units was granted in consideration of his responsibilities as the Partnership’s President and in consideration of his not having received a prior grant under this plan.

		Because Mr. Keating satisfied the RUP and LTIP-2 retirement criteria during fiscal 2008, all remaining unrecognized expense relative to his unvested awards was recognized during fiscal 2008 in accordance with the requirements of SFAS 123R.

(4)		For fiscal 2008, the amounts reported in this column represent each named executive officer’s annual cash bonus earned in accordance with the performance measures discussed under the subheading “Annual Cash Bonus Plan” in the “Compensation Discussion and Analysis.” For fiscal 2007, the amounts included in this column also include the interest credits made on behalf of the remaining balances of LTIP-2’s predecessor plan. Because the remaining balances of the predecessor plan were distributed to the participants during November 2007, there were no 2008 interest credits. The fiscal 2007 breakdown for each plan with respect to each named executive officer is as follows:


Plan Name	Mr. Alexander		Mr. Stivala		Mr. Dunn		Mr. Boyd		Mr. Keating
Cash Bonus	$	450,000	$	132,000	$	440,000	$	155,100	$	150,150
LTIP-1 Interest Credits		6,188		831		3,568		768		1,461

Totals	$	456,188	$	132,831	$	443,568	$	155,868	$	151,611


(5)		The amounts reported in this column represent each named executive officer’s Cash Balance Plan earnings for the year. The change in pension value and nonqualified deferred compensation earnings for fiscal 2008 was ($150,315), ($23,157), ($29,043) and ($57,881) for Messrs. Alexander, Dunn, Boyd and Keating, respectively. The change in pension value and nonqualified deferred compensation earnings for fiscal 2007 was ($1,460) and ($3,348) for Messrs. Alexander and Boyd, respectively. These amounts have been omitted from the table because they are negative. Mr. Stivala is not a participant in these plans.

(6)		The amounts reported in this column consist of the following:


2008
Type of Compensation	Mr. Alexander		Mr. Stivala		Mr. Dunn		Mr. Boyd		Mr. Keating
401(k) Match	$	3,450	$	3,450	$	3,450	$	3,450	$	3,300
Value of Annual Physical Examination		1,500		1,500		1,500		N/A		1,200
Value of Partnership Provided Vehicle		11,395		12,647		12,888		6,549		11,522
Tax Preparation Services		5,000		N/A		2,500		900		2,500
Cash Balance Plan Administrative Fees		1,500		N/A		1,500		1,500		1,500
Insurance Premiums		24,081		14,992		17,138		14,007		15,087

Totals	$	46,926	$	32,589	$	38,976	$	26,406	$	35,109


2007
Type of Compensation	Mr. Alexander		Mr. Stivala		Mr. Dunn		Mr. Boyd		Mr. Keating
401(k) Match	$	13,500	$	12,485	$	13,500	$	13,500	$	12,697
Value of Annual Physical Examination		1,200		1,200		1,200		N/A		1,500
Value of Partnership Provided Vehicle or, in Mr. Stivala’s Case, Car Allowance		11,078		4,675		10,198		5,647		11,522
Tax Preparation Services		2,000		N/A		2,000		950		2,000
Cash Balance Plan Administrative Fees		1,500		N/A		1,500		1,500		1,500
Insurance Premiums		23,229		13,996		16,481		12,605		14,597

Totals	$	52,507	$	32,356	$	44,879	$	34,202	$	43,816

Note: Column (f) was omitted from the Summary Compensation Table because the Partnership does not award options to its employees.

Grants of Plan Based Awards Table for Fiscal 2008

The following table sets forth certain information concerning grants of awards made to each named executive officer during the fiscal year ended September 27, 2008:

Phantom

Units

All Other stock

Grant Date

Underlying

Estimated Future Payments

Awards:

Fair Value of

Equity

Under Non-Equity Incentive

Under Equity Incentive

Number of

Stock and

Incentive

Plan Awards

Shares of Stock

Option

Plan

Grant

Approval

Plan Awards

Target

Maximum

Target

Maximum

or Units

Awards

Name

Date

(LTIP-2)⁽⁴⁾

($)

(#)

($)⁽⁵⁾

(a)

(b)

(d)

(e)

(g)

(h)

(i)

(l)

Mark A. Alexander

RUP ⁽¹⁾

N/A

Bonus⁽²⁾

28 Sep 07

450,000

495,000

LTIP-2⁽³⁾

28 Sep 07

2,989

135,910

169,876

Michael A. Stivala

RUP⁽¹⁾

3 Dec 07

31 Oct 07

2,272

80,054

Bonus⁽²⁾

28 Sep 07

162,500

178,750

LTIP-2⁽³⁾

28 Sep 07

1,871

85,074

106,354

Michael J. Dunn, Jr.

RUP ⁽¹⁾

3 Dec 07

31 Oct 07

29,533

1,040,593

Bonus⁽²⁾

28 Sep 07

425,000

467,500

LTIP-2⁽³⁾

28 Sep 07

4,894

222,530

278,186

Steven C. Boyd

RUP ⁽¹⁾

3 Dec 07

31 Oct 07

3,408

120,081

Bonus⁽²⁾

28 Sep 07

147,000

161,700

LTIP-2⁽³⁾

28 Sep 07

1,693

76,980

96,215

Michael M. Keating

RUP ⁽¹⁾

3 Dec 07

31 Oct 07

3,408

120,081

Bonus⁽²⁾

28 Sep 07

143,000

157,300

LTIP-2⁽³⁾

28 Sep 07

1,647

74,889

93,623


(1)		The quantities reported on these lines represent discretionary awards under the Partnership’s 2000 Restricted Unit Plan. RUP awards vest as follows: 25% of the award on the third anniversary of the grant date; 25% of the award on the fourth anniversary of the grant date; and 50% of the award on the fifth anniversary of the grant date. If a recipient has held an unvested award for at least six months; is 55 years or older; and has worked for the Partnership for at least ten years, an award held by such participant will vest six months following such participant’s retirement if the participant retires prior to the conclusion of the normal vesting schedule unless the Committee exercises its discretionary authority to alter the plan’s retirement provision in regard to a particular award. On September 27, 2008, Messrs. Dunn and Keating were the only named executive officers who held RUP awards and, at the same time, satisfied all three retirement eligibility criteria. However, as a condition of Mr. Dunn’s award, the Committee requires Mr. Dunn to hold his award for three years from the grant date before the plan’s retirement provisions become applicable. Detailed discussions of the general terms of the RUP and the facts and circumstances considered by the Committee in authorizing the 2008 awards to the named executive officers is included in the “Compensation Discussion and Analysis” under the subheading “2000 Restricted Unit Plan.”

(2)		Amounts reported on these lines are the targeted and maximum annual cash bonus compensation potential for each named executive officer under the annual cash bonus plan as described in the “Compensation Discussion and Analysis” under the subheading “Annual Cash Bonus Plan.” Actual amounts earned by the named executive officers for fiscal 2008 were equal to 95% of the “Target” amounts reported on this line. Column (c) (“Threshold $”) was omitted because the annual cash bonus plan does not provide for a minimum cash payment. Because these plan awards were granted to, and 95% of the “Target” awards were earned by, our named executive officers during fiscal 2008, 95% of the “Target” amounts reported under column (d) have been reported in the Summary Compensation Table above.

(3)		LTIP-2 is a phantom unit plan. As discussed in the “Compensation Discussion and Analysis” above, under the subheading “2003 Long-Term Incentive Plan,” in accordance with his employment agreement, Mr. Alexander’s award is based upon 30% of his annual target cash bonus; however, Mr. Dunn’s award (as are the awards of all of the other named executive officers) is based upon 52% of his annual target cash bonus. The different percentages account for the apparent differences between amounts reported for Mr. Alexander and for Mr. Dunn.

		Payments, if earned, are based on a combination of (1) the fair market value of our Common Units at the end of a three-year measurement period, which, for purposes of the plan, is the average of the closing prices for the twenty business days preceding the conclusion of the three-year measurement period, and (2) cash equal to the distributions that would have inured to the same quantity of outstanding Common Units during the same three-year measurement period. The fiscal 2008 award “Target ($)” and “Maximum ($)” amounts are estimates based upon (1) the fair market value (the average of the closing prices of our Common Units for the twenty business days preceding September 27, 2008) of our Common Units at the end of fiscal 2008, and (2) the estimated distributions over the course of the award’s three-year measurement period. Column (f) (“Threshold $”) was omitted because LTIP-2 does not provide for a minimum cash payment. Detailed descriptions of the plan and the calculation of awards are included in the “Compensation Discussion and Analysis” under the subheading “2003 Long-Term Incentive Plan.”

(4)		This column is frequently used when non-equity incentive plan awards are denominated in units; however, in this case, the numbers reported represent the phantom units each named executive officer was awarded under LTIP-2 during fiscal 2008.

(5)		The dollar amounts reported in this column represent the aggregate fair value of the RUP awards on the grant date, calculated in accordance with SFAS 123R. The fair value shown may not be indicative of the value realized in the future upon vesting due to the variability in the trading price of our Common Units.

Note: Columns (j) and (k) were omitted from the Grants of Plan Based Awards Table because the Partnership does not award options to its employees.

Outstanding Equity Awards at Fiscal Year End 2008 Table

The following table sets forth certain information concerning outstanding equity awards under our 2000 Restricted Unit Plan and phantom equity awards under our 2003 Long-Term Incentive Plan for each named executive officer as of September 27, 2008:


Stock Awards
					Equity Incentive
					Plan Awards:
					Number of		Equity Incentive Plan
			Market Value		Unearned		Awards: Market or
	Number of Shares		of Shares or		Shares, Units or		Payout Value of
	or Units of Stock		Units of Stock		Other Rights		Unearned Shares,
	That Have Not		That Have Not		that Have Not		Units or Other Rights
	Vested		Vested		Vested		That Have Not Vested
Name	(#)⁽⁵⁾		($)⁽⁶⁾		(#)⁽⁷⁾		($)⁽⁸⁾
(a)	(g)		(h)		(i)		(j)
Mark A. Alexander		—		—		6,996	$	316,355
Michael A. Stivala⁽¹⁾		13,946	$	476,605		3,474	$	157,261
Michael J. Dunn, Jr.⁽²⁾		29,533	$	1,009,290		11,068	$	500,561
Steven C. Boyd⁽³⁾		16,804	$	574,277		3,730	$	168,711
Michael M. Keating⁽⁴⁾		5,606	$	191,585		3,754	$	169,772


(1)		Mr. Stivala’s RUP awards will vest as follows:

Oct. 1,

Nov. 1,

Oct. 1,

Nov. 1,

Apr. 25,

Oct. 1,

Nov. 1,

Dec. 3,

Apr. 25,

Dec. 3,

Apr. 25,

Dec. 3,

Vesting Date

2008

2009

2010

2011

2012

Quantity of Units

870

1,200

870

900

1,374

1,738

600

568

1,374

568

2,748

1,136


(2)		Despite Mr. Dunn’s having met the plan’s retirement criteria, this award will not be subject to the plan’s retirement provisions until December 3, 2010. For more information on this and the retirement provision, refer to the subheading “2000 Restricted Unit Plan” in the “Compensation Discussion and Analysis.” If Mr. Dunn does not retire prior to the conclusion of the normal vesting schedule of his award, his award will vest as follows:

Dec. 3,

Vesting Date

2010

2011

2012

Quantity of Units

7,384

14,765


(3)		Mr. Boyd’s RUP awards will vest as follows:

Nov. 1,

Apr. 25,

Nov. 1,

Dec. 3,

Apr. 25,

Dec. 3,

Apr. 25,

Dec. 3,

Vesting Date

2008

2009

2010

2011

2012

Quantity of Units

2,500

2,200

1,374

3,200

852

1,374

852

2,748

1,704


(4)		Mr. Keating met the retirement eligibility criteria (explained under the subheading “2000 Restricted Unit Plan” in the “Compensation Discussion and Analysis”) during fiscal 2008. If he does not retire prior to the conclusion of the normal vesting schedule of his award, his award will vest as follows:

Apr. 25,

Dec. 3,

Apr. 25,

Dec. 3,

Apr. 25,

Dec. 3,

Vesting Date

2010

2011

2012

2011

Quantity of Units

550

852

550

852

1,098

1,704


(5)		The figures reported in this column represent the total quantity of each of our named executive officer’s unvested RUP awards.

(6)		The figures reported in this column represent the figures reported in column (g) multiplied by the average of the highest and the lowest trading prices of our Common Units on September 26, 2008, the last trading day of fiscal 2008.

(7)		The amounts reported in this column represent the quantities of phantom units that underlie the outstanding fiscal 2007 and fiscal 2008 awards under LTIP-2. Payments, if earned, will be made to participants at the end of a three-year measurement period and will be based upon our total return to Common Unitholders in comparison to the total return provided by a predetermined peer group of eleven other companies, all of which are publicly-traded partnerships, to their unitholders. For more information on LTIP-2, refer to the subheading “2003 Long-Term Incentive Plan” in the “Compensation Discussion and Analysis.”


(8)		The amounts reported in this column represent the estimated future target payouts of the fiscal 2007 and fiscal 2008 LTIP-2 awards. These amounts were computed by multiplying the quantities of the unvested phantom units in column (i) by the average of the closing prices of our Common Units for the twenty business days preceding September 27, 2008 (in accordance with the plan’s valuation methodology), and by adding to the product of that calculation the product of each year’s underlying phantom units times the sum of the distributions that are estimated to inure to an outstanding Common Unit during each award’s three-year measurement period. Due to the variability in the trading prices of our Common Units, as well as our performance relative to the peer group, actual payments, if any, at the end of the three-year measurement period may differ. The following chart provides a breakdown of each year’s awards:


	Mr. Alexander		Mr. Stivala		Mr. Dunn		Mr. Boyd		Mr. Keating
Fiscal 2007 Phantom Units		4,007		1,603		6,174		2,037		2,107
Value of Fiscal 2007 Phantom Units	$	144,182	$	57,680	$	222,156	$	73,296	$	75,815
Estimated Distributions over Measurement Period	$	36,263	$	14,507	$	55,875	$	18,435	$	19,068

Fiscal 2008 Phantom Units		2,989		1,871		4,894		1,693		1,647
Value of Fiscal 2008 Phantom Units	$	107,552	$	67,323	$	176,098	$	60,918	$	59,263
Estimated Distributions over Measurement Period	$	28,358	$	17,751	$	46,432	$	16,062	$	15,626

Note: Columns (b), (c), (d), (e) and (f), all of which are for the reporting of option-related compensation, have been omitted from the Outstanding Equity Awards At Fiscal Year End Table because we do not grant options to our employees.

Equity Vested Table for Fiscal 2008

Awards under the 2000 Restricted Unit Plan are settled in Common Units upon vesting. Awards under the 2003 Long-Term Incentive Plan, a phantom-equity plan, are settled in cash. The following two tables set forth certain information concerning all vesting of awards under our 2000 Restricted Unit Plan and the vesting of the fiscal 2006 award under our 2003 Long-Term Incentive Plan for each named executive officer during the fiscal year ended September 27, 2008:


2000 Restricted Unit Plan	Unit Awards
	Number of
	Common
	Units
	Acquired on		Value
	Vesting		Realized on
Name	(#)		Vesting ($)⁽¹⁾
Mark A. Alexander		—		—
Michael A. Stivala		1,200	$	57,654
Michael J. Dunn, Jr.		—		—
Steven C. Boyd		1,200	$	57,654
Michael M. Keating		—		—


(1)		The value realized is equal to the average of the high and low trading prices of our Common Units on the vesting date, multiplied by the number of units that vested.



2003 Long-Term Incentive Plan — Fiscal 2006⁽²⁾ Award	Cash Awards
	Number of
	Phantom
	Units
	Acquired on		Value
	Vesting		Realized on
Name	(#)⁽³⁾		Vesting ($)⁽⁴⁾
Mark A. Alexander		4,328	$	239,704
Michael A. Stivala		1,472	$	81,526
Michael J. Dunn, Jr.		6,252	$	346,263
Steven C. Boyd		1,645	$	91,107
Michael M. Keating		2,092	$	115,864


(2)		The fiscal 2006 award’s three-year measurement period concluded on September 27, 2008.

(3)		In accordance with the formula described in the “Compensation Discussion and Analysis” under the subheading “2003 Long-Term Incentive Plan,” these quantities were calculated at the beginning of the three-year measurement period and were, therefore, based upon each individual’s salary and target cash bonus at that time.

(4)		The value (i.e., cash payment) realized was calculated in accordance with the terms and conditions of LTIP-2. For more information, refer to the subheading “2003 Long-Term Incentive Plan” in the “Compensation Discussion and Analysis.”

Pension Benefits Table for Fiscal 2008

The following table sets forth certain information concerning each plan that provides for payments or other benefits at, following, or in connection with retirement for each named executive officer as of the end of the fiscal year ended September 27, 2008:


		Number		Present Value
		of Years		of		Payments
		Credited		Accumulated		During Last
		Service		Benefit		Fiscal Year
Name	Plan Name	(#)		($)		($)
Mark A. Alexander	SERP ⁽¹⁾		7	$	365,988	$	—
	Cash Balance Plan ⁽²⁾		7	$	141,307	$	—

Michael A. Stivala⁽³⁾	N/A		N/A	$	—	$	—

Michael J. Dunn, Jr.	SERP ⁽¹⁾		6	$	40,990	$	—
	Cash Balance Plan⁽²⁾		6	$	175,268	$	—
	LTIP-2 ⁽⁴⁾		N/A	$	500,561	$	—

Steven C. Boyd	Cash Balance Plan ⁽²⁾		15	$	66,745	$	—

Michael M. Keating	Cash Balance Plan ⁽²⁾		15	$	280,342	$	—
	LTIP-2 ⁽⁴⁾		N/A	$	169,772	$	—
	RUP⁽⁵⁾		N/A	$	191,585	$	—


(1)		Mr. Alexander and Mr. Dunn are the only employees who participate in the SERP. Provided that the SERP requirements are met (retirement at age 55 or older and having provided ten or more years of service to the Partnership), Mr. Alexander will receive a monthly benefit of $6,737 and Mr. Dunn will receive a monthly benefit of $373. For more information on the SERP, refer to the subheading “Supplemental Executive Retirement Plan” in the “Compensation Discussion and Analysis.”

(2)		For more information on the Cash Balance Plan, refer to the subheading “Pension Plan” in the “Compensation Discussion and Analysis.”

(3)		Because Mr. Stivala commenced employment with the Partnership after January 1, 2000, the date on which the Cash Balance Plan was closed to new participants, he does not participate in the Cash Balance Plan.

(4)		Currently, Mr. Dunn and Mr. Keating are the only named executive officers who meet the retirement criteria of the LTIP-2 plan document. For such participants, upon retirement, outstanding but unvested LTIP-2 awards become fully vested. However, payouts on those awards are deferred until the conclusion of each outstanding award’s three-year measurement period, based on the outcome of the TRU relative to the peer group. The number reported on this line represents a projected payout of Mr. Dunn’s and Mr. Keating’s outstanding fiscal 2007 and fiscal 2008 LTIP-2 awards. Because the ultimate payout, if any, is predicated on the trading prices of the Partnership’s Common Units at the end of the three-year measurement period, as well as where, within the peer group, our TRU falls, the value reported may not be indicative of the value realized in the future upon vesting due to the variability in the trading price of our Common Units.

(5)		Currently, Mr. Keating is the only named executive officer who meets the retirement criteria of the RUP document. For such participants, upon retirement, outstanding RUP awards vest six months after retirement. The value reported in this table is identical to the value of 5,606 Common Units on September 27, 2008.

Potential Payments Upon Termination

Potential Payments upon Termination to Named Executive Officers with Employment Agreements

The following table sets forth certain information concerning the potential payments to Mr. Alexander and Mr. Dunn under their employment agreements, the SERP and LTIP-2 for the circumstances listed in the table assuming a September 27, 2008 termination date:

Involuntary

Termination

Without Cause

by the

Partnership or

by the

Executive for

Good Reason

without a

with a Change

Change of

of Control

Executive Payments and Benefits Upon Termination

Death

Disability

Control Event

Event

Mark A. Alexander

Cash Compensation⁽¹⁾

⁽³⁾

⁽⁴⁾

1,350,000

2,835,000

Accelerated Vesting of Fiscal 2007 and 2008 LTIP-2 Awards⁽²⁾

N/A

355,505

SERP⁽⁵⁾

220,600

287,000

449,100

Medical Benefits

N/A

35,388

280G Tax Gross-up

N/A

409A Tax Gross-up

N/A

Total

220,600

287,000

1,385,388

3,674,993

Michael J. Dunn, Jr.

Cash Compensation⁽¹⁾

⁽³⁾

⁽⁴⁾

850,000

1,785,000

Accelerated Vesting of Fiscal 2007 and 2008 LTIP-2 Awards⁽²⁾

N/A

561,852

Accelerated Vesting of Outstanding RUP Awards⁽⁶⁾

N/A

1,009,290

SERP

29,800

52,400

38,500

Medical Benefits

N/A

23,592

280G Tax Gross-up

N/A

409A Tax Gross-up

N/A

Total

29,800

52,400

925,992

3,418,234


(1)		For more information on the cash compensation payable to the two named executive officers with whom we have entered into employment agreements, refer to the subheading “Employment Agreements” in the “Compensation Discussion and Analysis.”

(2)		In the event of a change of control, all LTIP-2 awards will vest immediately regardless of whether termination immediately follows. If a change of control event occurs, the calculation of the LTIP-2 payment will be made as if our total return to Common Unitholders was higher than that provided by any of the other members of the peer group to their unitholders. For more information, refer to the subheading “2003 Long-Term Incentive Plan” in the “Compensation Discussion and Analysis.” In the event of death, the inability to continue employment due to permanent disability, or a termination without cause or a good reason resignation unconnected to a change of control event, awards will vest in accordance with the normal vesting schedule and will be subject to the same requirements as awards held by individuals still employed by the Partnership and shall be subject to the same risks as awards held by all other participants.

(3)		In the event of death, Mr. Alexander’s and Mr. Dunn’s estates are entitled to a payment equal to the decedent’s earned but unpaid salary and pro-rata cash bonus at the time of death.

(4)		In the event of disability, each is entitled to a payment equal to his earned but unpaid salary and pro-rata cash bonus.

(5)		Because Mr. Alexander had not attained age 55 on September 27, 2008, if any of the above hypothetical events had occurred on that date, only death, disability or a change of control would give rise to a SERP-related payment. Change of control related payments are due to Mr. Alexander and Mr. Dunn within 30 days of the change of control event, regardless of whether termination or resignation follows the event. In the event of death, Mr. Alexander’s estate would have received a lump sum payment of $220,600. In the event of disability, if Mr. Alexander remained disabled until age 55, he would be eligible for a lump sum payment, at that time, of $864,200. The figure $287,000 reported in the table represents the present value of the hypothetical future payment.

(6)		The RUP document makes no provisions for the vesting of grants held by recipients who die prior to the completion of the vesting schedule. If a recipient of a RUP grant becomes permanently disabled, only those grants that have been held for at least one year on the date that the employee’s employment is terminated as a result of his or her permanent disability shall immediately vest; all grants held by the recipient for less than one year shall be forfeited by the recipient. Because Mr. Dunn’s RUP grant was awarded less than one year prior to September 27, 2008, if he had become permanently disabled on September 27, 2008, his RUP grant would have been forfeited.

		Under circumstances unrelated to a change of control, if a RUP grant recipient’s employment is terminated without cause or he or she resigns for good reason, any RUP grants held by such recipient shall be forfeited.

		In the event of a change of control, as defined in the RUP document, all unvested RUP grants shall vest immediately on the date the change of control is consummated, regardless of the holding period and regardless of whether the recipient’s employment is terminated.

Potential Payments upon Termination to Named Executive Officers without Employment Agreements

The following table sets forth certain information containing potential payments to the three named executive officers without employment agreements in accordance with the provisions of the Severance Protection Plan, the RUP and LTIP-2 for the circumstances listed in the table assuming a September 27, 2008 termination date:

Involuntary

Termination

Involuntary

Without Cause

Termination

by the

Without Cause

Partnership or

by the

Partnership or

Executive for

by the

Good Reason

Executive for

without a

Good Reason

Change of

with a Change

Control

of Control

Executive Payments and Benefits Upon Termination

Death

Disability

Event⁽⁶⁾

Event

Michael A. Stivala

Cash Compensation⁽¹⁾

⁽³⁾

⁽⁴⁾

250,000

618,750

Accelerated Vesting of Fiscal 2007 and 2008 LTIP-2 Awards⁽²⁾

N/A

170,198

Accelerated Vesting of Outstanding RUP Awards⁽⁵⁾

N/A

398,959

N/A

476,605

Medical Benefits

N/A

11,796

N/A

280G Tax Gross-up

N/A

409A Tax Gross-up

N/A

Total

398,959

261,796

1,265,553

Steven C. Boyd

Cash Compensation⁽¹⁾

⁽³⁾

⁽⁴⁾

245,000

588,000

Accelerated Vesting of Fiscal 2007 and 2008 LTIP-2 Awards⁽²⁾

N/A

189,196

Accelerated Vesting of Outstanding RUP Awards⁽⁵⁾

N/A

457,808

N/A

574,276

Medical Benefits

N/A

10,464

N/A

280G Tax Gross-up

N/A

409A Tax Gross-up

N/A

Total

457,808

255,464

1,351,472

Michael M. Keating

Cash Compensation⁽¹⁾

⁽³⁾

⁽⁴⁾

220,000

544,500

Accelerated Vesting of Fiscal 2007 and 2008 LTIP-2 Awards⁽²⁾

N/A

190,611

Accelerated Vesting of Outstanding RUP Awards⁽⁵⁾

N/A

75,117

N/A

191,585

Medical Benefits

N/A

11,796

N/A

280G Tax Gross-up

N/A

409A Tax Gross-up

N/A

Total

75,117

231,796

926,696


(1)		In the event of a change of control followed by a termination without cause or by a resignation with good reason, each of the named executive officers without employment agreements will receive 78 weeks of base pay plus a sum equal to their annual target cash bonus divided by 52 and multiplied by 78 in accordance with the terms of the Severance Protection Plan. For more information on the Severance Protection Plan, refer to the subheading “Change of Control” in the “Compensation Discussion and Analysis.”

(2)		In the event of a change of control, all LTIP-2 awards will vest immediately regardless of whether termination immediately follows. If a change of control event occurs, the calculation of the LTIP-2 payment will be made as if our total return to Common Unitholders was higher than that provided by any of the other members of the peer group to their unitholders. For more information, refer to the subheading “2003 Long-Term Incentive Plan” in the “Compensation Discussion and Analysis.”

		In the event of death, the inability to continue employment due to permanent disability, or a termination without cause or a good reason resignation unconnected to a change of control event, awards will vest in accordance with the normal vesting schedule and will be subject to the same requirements as awards held by individuals still employed by the Partnership and shall be subject to the same risks as awards held by all other participants.

(3)		In the event of death, the named executive officer’s estate is entitled to a payment equal to the decedent’s earned but unpaid salary and pro-rata cash bonus.

(4)		In the event of disability, the named executive officer is entitled to a payment equal to his earned but unpaid salary and pro-rata cash bonus.

(5)		The RUP document makes no provisions for the vesting of grants held by recipients who die prior to the completion of the vesting schedule. If a recipient of a RUP grant becomes permanently disabled, only those grants that have been held for at least one year on the date that the employee’s employment is terminated as a result of his or her permanent disability shall immediately vest; all grants held by the recipient for less than one year shall be forfeited by the recipient. Because Mr. Stivala, Mr. Boyd and Mr. Keating each received a unit grant during fiscal 2008, if any or all of the three had become permanently disabled on September 27, 2008, the following quantities of unvested restricted units would have vested: Stivala, 11,674; Boyd, 13,396; Keating, 2,198 and the following quantities would have been forfeited: Stivala, 2,272; Boyd, 3,408; Keating, 3,408.


		Under circumstances unrelated to a change of control, if a RUP grant recipient’s employment is terminated without cause or he or she resigns for good reason, any RUP grants held by such recipient shall be forfeited.

		In the event of a change of control, as defined in the RUP document, all unvested RUP grants shall vest immediately on the date the change of control is consummated, regardless of the holding period and regardless of whether the recipient’s employment is terminated.

(6)		Any severance benefits, unrelated to a change of control event, payable to these officers would be determined by the Committee on a case-by-case basis in accordance with prior treatment of other similarly situated executives and may, as a result, differ from this hypothetical presentation. For purposes of this table, we have assumed that each of these named executive officers would, upon termination of employment without cause or for resignation for good reason, receive accrued salary and benefits through the date of termination plus one times annual salary, paid in the form of salary continuation, and continued participation, at active employee rates, in the Partnership’s health insurance plans for one year.

SUPERVISORS’ COMPENSATION

The following table sets forth the compensation of the non-employee members of the Board of Supervisors of the Partnership during fiscal 2008.


	Fees Earned
	or Paid in
	Cash		Unit Awards		Total
Supervisor	($) ⁽¹⁾		($) ⁽²⁾		($)

John D. Collins	$	75,000	$	49,861	$	124,861
Harold R. Logan, Jr.		100,000		—		100,000
Dudley C. Mecum		75,000		—		75,000
John Hoyt Stookey		75,000		—		75,000
Jane Swift		75,000		49,861		124,861


(1)		Includes amounts earned for fiscal 2008, including quarterly retainer installments for the fourth quarter of 2008 that were paid in October 2008. Does not include amounts paid in fiscal 2008 for fiscal 2007 quarterly retainer installments.

(2)		Represents the dollar amount charged to earnings for financial statement reporting purposes during fiscal 2008 pursuant to SFAS 123R for restricted unit grants of 5,496 awarded to both Mr. Collins and Ms. Swift on April 25, 2007. All grants were made in accordance with the provisions of our 2000 Restricted Unit Plan and vest accordingly. The average of the high and low sales price, discounted for projected distributions during the vesting period, was used to calculate the value of the restricted unit grants for purposes of amortizing compensation expense under SFAS 123R. Because Messrs. Logan, Mecum and Stookey have met the plan’s retirement provisions, all expense for their unvested grants was previously recognized. As of September 27, 2008, each non-employee member of the Board of Supervisors held the following quantities of unvested restricted unit grants: Mr. Collins, 5,496 units; Mr. Logan, 9,375 units; Mr. Mecum, 9,375 units; Mr. Stookey, 9,375 units; and Ms. Swift, 5,496 units.

Note: The columns for reporting option awards, non-equity incentive plan compensation, changes in pension value and non-qualified deferred compensation plan earnings and all other forms of compensation were omitted from the Supervisor’s Compensation Table because the Partnership does not provide these forms of compensation to its non-employee supervisors.

Fees and Benefit Plans for Non-Employee Supervisors

Annual Cash Retainer Fees. As the Chairman of the Board of Supervisors, Mr. Logan receives an annual retainer of $100,000, payable in quarterly installments of $25,000 each. Each of the other supervisors receives an annual cash retainer of $75,000, payable in quarterly installments of $18,750 each.

Meeting Fees. The members of our Board of Supervisors receive no additional remuneration for attendance at regularly scheduled meetings of the Board or its Committees, other than reimbursement of reasonable expenses incurred in connection with such attendance.


ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS

The following table sets forth certain information as of November 24, 2008 regarding the beneficial ownership of Common Units by each member of the Board of Supervisors, each executive officer named in the Summary Compensation Table in Item 11 of this Annual Report, and all members of the Board of Supervisors and executive officers as a group. Based upon filings under Section 13(d) or (g) under the Exchange Act, the Partnership does not know of any person or group who beneficially owns more than 5% of the outstanding Common Units. Except as set forth in the notes to the table, each individual or entity has sole voting and investment power over the Common Units reported.


	Amount and Nature of		Percent
Name of Beneficial Owner	Beneficial Ownership		of Class
Mark A. Alexander (a)		1,298,912		3.9	%
Michael J. Dunn, Jr. (b)		208,947		*
Michael A. Stivala (c)		8,962		*
Steven C. Boyd (d)		29,733		*
Michael M. Keating (e)		98,500		*

John Hoyt Stookey (f)		14,072		*
Harold R. Logan, Jr.(f)		14,854		*
Dudley C. Mecum (f)		9,884		*
John D. Collins (g)		12,450		*
Jane Swift (g)		-0-		*

All Members of the Board of Supervisors and Executive Officers as a Group (17 persons) (h)		1,823,188		5.5	%


*		Less than 1%.

(a)		Includes 784 Common Units held by the General Partner, of which Mr. Alexander is the sole member. Includes 1,298,128 Common Units which are held in a brokerage account, where there is a possibility that such Common Units could be pledged as security.

(b)		Excludes 29,533 unvested restricted units, none of which will vest in the 60-day period following November 24, 2008. Restricted unit grants vest 25%, 25% and 50%, respectively, on the third, fourth and fifth anniversaries of the date of grant and 100% upon a “change in control”, as defined in the Partnership’s 2000 Restricted Unit Plan.

(c)		Excludes 11,876 unvested restricted units, none of which will vest in the 60-day period following November 24, 2008. Restricted unit grants vest 25%, 25% and 50%, respectively, on the third, fourth and fifth anniversaries of the date of grant and 100% upon a “change in control”, as defined in the Partnership’s 2000 Restricted Unit Plan.

(d)		Excludes 14,304 unvested restricted units, none of which will vest in the 60-day period following November 24, 2008. Restricted unit grants vest 25%, 25% and 50%, respectively, on the third, fourth and fifth anniversaries of the date of grant and 100% upon a “change in control”, as defined in the Partnership’s 2000 Restricted Unit Plan. Includes 29,733 Common Units which are held in a brokerage account, where there is a possibility that such Common Units could be pledged as security.

(e)		Excludes 5,606 unvested restricted units, none of which will vest in the 60-day period following November 24, 2008. Restricted unit grants vest 25%, 25% and 50%, respectively, on the third, fourth and fifth anniversaries of the date of grant and 100% upon a “change in control”, as defined in the Partnership’s 2000 Restricted Unit Plan.

(f)		Excludes 7,250 unvested restricted units, none of which will vest in the 60-day period following November 24, 2008. Restricted unit grants vest 25%, 25% and 50%, respectively, on the third, fourth and fifth anniversaries of the date of grant and 100% upon a “change in control”, as defined in the Partnership’s 2000 Restricted Unit Plan.


(g)		Excludes 5,496 unvested restricted units, none of which will vest in the 60-day period following November 24, 2008. Restricted unit grants vest 25%, 25% and 50%, respectively, on the third, fourth and fifth anniversaries of the date of grant and 100% upon a “change in control”, as defined in the Partnership’s 2000 Restricted Unit Plan.

(h)		Inclusive of the units referred to in footnotes (b), (c), (e), (f) and (g) above, the reported number of units excludes 145,059 unvested restricted units, none of which will vest in the 60 day period following November 20, 2007, owned by certain executive officers, whose restricted units vest on the same basis as described in footnotes (b), (c), (e), (f) and (g) above. Includes 1,822,404 Common Units which are held in a brokerage account, where there is a possibility that such Common Units could be pledged as security (inclusive of the units referred to in footnotes (a) and (d) above).

Securities Authorized for Issuance Under the 2000 Restricted Unit Plan

The following table sets forth certain information, as of September 27, 2008, with respect to the Partnership’s 2000 Restricted Unit Plan, under which restricted units of the Partnership, as described in the Notes to the Consolidated Financial Statements included in this Annual Report, are authorized for issuance.

Number of restricted units

remaining available for

Number of Common

Weighted-

future issuance under the

Units to be issued

average grant

2000 Restricted Unit Plan

upon vesting of

date fair value per

(excluding securities

restricted units

restricted unit

reflected in column (a))

Plan Category

(a)

(b)

(c)

Equity compensation plans approved by security holders (1)

446,515

(2)

30.57

89,874

Equity compensation plans not approved by security holders

—

Total

446,515

30.57

89,874


(1)		Relates to the 2000 Restricted Unit Plan.

(2)		Represents number of restricted units that, as of September 27, 2008, had been granted under the 2000 Restricted Unit Plan but had not yet vested.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

Related Person Transactions

None.

Supervisor Independence

The Corporate Governance Guidelines and Principles adopted by the Board of Supervisors provide that a Supervisor is deemed to be lacking a material relationship to the Partnership and is therefore independent of management if the following criteria are satisfied:

Within the past three years, the Supervisor:

	a.		has not been employed by the Partnership and has not received more than $100,000 per year in direct compensation from the Partnership, other than Supervisor and committee fees and pension or other forms of deferred compensation for prior service;

	b.		has not provided significant advisory or consultancy services to the Partnership, and has not been affiliated with a company or a firm that has provided such services to the Partnership in return for aggregate payments during any of the last three fiscal years of the Partnership in excess of the greater of 2% of the other company’s consolidated gross revenues or $1 million;

	c.		has not been a significant customer or supplier of the Partnership and has not been affiliated with a company or firm that has been a customer or supplier of the Partnership and has either made to the Partnership or received from the Partnership payments during any of the last three fiscal years of the Partnership in excess of the greater of 2% of the other company’s consolidated gross revenues or $1 million;

	d.		has not been employed by or affiliated with an internal or external auditor that within the past three years provided services to the Partnership; and

	e.		has not been employed by another company where any of the Partnership’s current executives serve on that company’s compensation committee;

2.		The Supervisor is not a spouse, parent, sibling, child, mother- or father-in-law, son- or daughter-in-law or brother- or sister-in-law of a person having a relationship described in 1. above nor shares a residence with such person;

3.		The Supervisor is not affiliated with a tax-exempt entity that within the past 12 months received significant contributions from the Partnership (contributions of the greater of 2% of the entity’s consolidated gross revenues or $1 million are considered significant); and

4.		The Supervisor does not have any other relationships with the Partnership or with members of senior management of the Partnership that the Board determines to be material.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The following table sets forth the aggregate fees for services related to fiscal years 2008 and 2007 provided by PricewaterhouseCoopers LLP, our independent registered public accounting firm.


	Fiscal		Fiscal
	2008		2007

Audit Fees (a)	$	2,325,000	$	2,275,000
Audit-Related Fees (b)		84,000		145,000
Tax Fees (c)		722,000		848,000
All Other Fees (d)		—		2,000


(a)		Audit Fees consist of professional services rendered for the integrated audit of our annual consolidated financial statements and our internal control over financial reporting, including reviews of our quarterly financial statements, as well as the issuance of consents in connection with other filings made with the SEC.

(b)		Audit-Related Fees consist of professional services rendered in connection with acquisition-related due diligence and consultations concerning financial accounting and reporting standards.

(c)		Tax Fees consist of fees for professional services related to tax reporting, tax compliance and transaction services assistance.

(d)		All Other Fees represent fees for services provided to us not otherwise included in the categories above.

The Audit Committee of the Board of Supervisors has adopted a formal policy concerning the approval of audit and non-audit services to be provided by the independent registered public accounting firm, PricewaterhouseCoopers LLP. The policy requires that all services PricewaterhouseCoopers LLP may provide to us, including audit services and permitted audit-related and non-audit services, be pre-approved by the Audit Committee. The Audit Committee pre-approved all audit and non-audit services provided by PricewaterhouseCoopers LLP during fiscal 2008 and fiscal 2007.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated:


Signature		Title	Date

By:	/s/ MARK A. ALEXANDER (Mark A. Alexander)	Chief Executive Officer and Supervisor	November 26, 2008

By:	/s/ MICHAEL J. DUNN, JR (Michael J. Dunn, Jr.)	President and Supervisor	November 26, 2008

By:	/s/ HAROLD R. LOGAN, JR. (Harold R. Logan, Jr.)	Chairman and Supervisor	November 26, 2008

By:	/s/ JOHN HOYT STOOKEY (John Hoyt Stookey)	Supervisor	November 26, 2008

By:	/s/ DUDLEY C. MECUM (Dudley C. Mecum)	Supervisor	November 26, 2008

By:	/s/ JOHN D. COLLINS (John D. Collins)	Supervisor	November 26, 2008

By:	/s/ JANE SWIFT (Jane Swift)	Supervisor	November 26, 2008

By:	/s/ MICHAEL A. STIVALA (Michael A. Stivala)	Chief Financial Officer and Chief Accounting Officer	November 26, 2008

By:	/s/ MICHAEL A. KUGLIN (Michael A. Kuglin)	Controller	November 26, 2008

INDEX TO EXHIBITS

The exhibits listed on this Exhibit Index are filed as part of this Annual Report. Exhibits required to be filed by Item 601 of Regulation S-K, which are not listed below, are not applicable.


Exhibit
Number		Description

	2.1	Exchange Agreement dated as of July 27, 2006 by and among the Partnership, the Operating Partnership and the General Partner. (Incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed July 28, 2006).

	3.1	Third Amended and Restated Agreement of Limited Partnership of the Partnership dated as of October 19, 2006, as amended as of July 31, 2007. (Incorporated by reference to Exhibit 3.1 to the Partnership’s Current Report on Form 8-K filed August 2, 2007).

	3.2	Third Amended and Restated Agreement of Limited Partnership of the Operating Partnership dated as of October 19, 2006. (Incorporated by reference to Exhibit 3.2 to the Partnership’s Current Report on Form 8-K filed October 19, 2006).

	4.1	Description of Common Units of the Partnership. (Incorporated by reference to Exhibit 4.1 to the Partnership’s Current Report on Form 8-K filed October 19, 2006).

	4.2	Indenture, dated as of December 23, 2003, between Suburban Propane Partners, L.P., Suburban Energy Finance Corp. and The Bank of New York, as Trustee (including Form of Senior Global Exchange Note). (Incorporated by reference to Exhibit 10.28 to the Partnership’s Quarterly Report on Form 10-Q for the fiscal quarter ended December 27, 2003).

	4.3	Exchange and Registration Rights Agreement, dated December 23, 2003 among Suburban Propane Partners, L.P., Suburban Energy Finance Corp., Wachovia Capital Markets, LLC and Goldman, Sachs & Co. (Incorporated by reference to Exhibit 4.1 to the Partnership’s Registration Statement on Form S-4 dated December 19, 2003).

	4.4	Exchange and Registration Rights Agreement, dated March 31, 2005 among Suburban Propane Partners, L.P., Suburban Energy Finance Corp., Wachovia Capital Markets, LLC and Goldman, Sachs & Co. (Incorporated by reference to Exhibit 4.1 to the Partnership’s Current Report on Form 8-K filed April 1, 2005).

	10.1	Amended and Restated Employment Agreement dated as of November 13, 2008 between the Operating Partnership and Mr. Alexander. (Filed herewith).

	10.5	Amended and Restated Employment Agreement dated as of November 13, 2008 between the Operating Partnership and Mr. Dunn. (Filed herewith).

	10.6	Suburban Propane Partners, L.P. 2000 Restricted Unit Plan, as amended and restated effective October 17, 2006 and as further amended on July 31, 2007, October 31, 2007 and January 24, 2008. (Incorporated by reference to Exhibit 10.1 to the Partnership’s Quarterly Report on Form 10-Q for the fiscal quarter ended December 29, 2007).

	10.7	Suburban Propane, L.P. Severance Protection Plan, as amended on January 24, 2008. (Incorporated by reference to Exhibit 10.3 to the Partnership’s Quarterly Report on Form 10-Q for the fiscal quarter ended December 29, 2007).

E-1


Exhibit
Number		Description

	10.8	Form of Amendment to Suburban Propane Severance Protection Plan for Key Employees, adopted November 2, 2005. (Incorporated by reference to Exhibit 10.7 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 24, 2005).

	10.9	Suburban Propane, L.P. Long Term Incentive Plan, as amended and restated effective October 1, 1999. (Incorporated by reference to Exhibit 10.19 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 28, 2002).

	10.10	Form of Amendment to Suburban Propane, L.P. Long Term Incentive Program, adopted November 2, 2005. (Incorporated by reference to Exhibit 10.9 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 24, 2005).

	10.11	Suburban Propane L.P. 2003 Long Term Incentive Plan, as amended on October 17, 2006 and as further amended on July 31, 2007, October 31, 2007 and January 24, 2008. (Incorporated by reference to Exhibit 10.2 to the Partnership’s Quarterly Report on Form 10-Q for the fiscal quarter ended December 29, 2007).

	10.15	Amended and Restated Supplemental Executive Retirement Plan of the Partnership (effective as of January 1, 1998). (Incorporated by reference to Exhibit 10.23 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 29, 2001).

	10.16	Amended and Restated Retirement Savings and Investment Plan of Suburban Propane effective as of January 1, 1998). (Incorporated by reference to Exhibit 10.24 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 29, 2001).

	10.17	Amendment No. 1 to the Retirement Savings and Investment Plan of Suburban Propane (effective January 1, 2002). (Incorporated by reference to Exhibit 10.25 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 28, 2002).

	10.18	Third Amended and Restated Credit Agreement dated October 20, 2004, as amended by the First Amendment thereto dated March 17, 2005, as further amended by the Second Amendment thereto dated August 25, 2005. (Incorporated by reference to the Partnership’s Current Report on Form 8-K filed August 29, 2005).

	10.19	First Amendment to the Third Amended and Restated Credit Agreement dated as of March 11, 2005. (Incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed April 1, 2005).

	10.20	Second Amendment to the Third Amended and Restated Credit Agreement dated as of August 26, 2005. (Incorporated by reference to the Partnership’s Current Report on Form 8-K filed August 29, 2005).

	10.21	Third Amendment to the Third Amended and Restated Credit Agreement dated as of February 9, 2006. (Incorporated by reference to the Partnership’s Current Report on Form 8-K filed February 24, 2006).

	10.22	Distribution, Release and Lockup Agreement, dated as of July 27, 2006, between the Partnership, the Operating Partnership, the General Partner and the members of the General Partner. (Incorporated by reference to Exhibit 10.2 to the Partnership’s Current Report on Form 8-K filed July 28, 2006).

E-2


Exhibit
Number		Description

	10.23	Purchase and Sale Agreement, dated September 17, 2007, among Suburban Propane, L.P., Suburban Pipeline LLC and Plains LPG Services, L.P. (Incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed September 20, 2007).

	10.24	Non-Competition Agreement, dated September 17, 2007, between Suburban Propane, L.P. and Plains LPG Services, L.P. (Incorporated by reference to Exhibit 10.2 to the Partnership’s Current Report on Form 8-K filed September 20, 2007).

	10.25	Propane Storage Agreement, dated September 17, 2007, between Suburban Propane, L.P. and Plains LPG Services, L.P. (Incorporated by reference to Exhibit 10.3 to the Partnership’s Current Report on Form 8-K filed September 20, 2007).

	21.1	Subsidiaries of Suburban Propane Partners, L.P. (Filed herewith).

	23.1	Consent of PricewaterhouseCoopers LLP. (Filed herewith).

	31.1	Certification of the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. (Filed herewith).

	31.2	Certification of the Chief Financial Officer and Chief Accounting Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. (Filed herewith).

	32.1	Certification of the Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (Filed herewith).

	32.2	Certification of the Chief Financial Officer and Chief Accounting Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (Filed herewith).

E-3

Report of Independent Registered Public Accounting Firm

To the Board of Supervisors and Unitholders of
Suburban Propane Partners, L.P.

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, partners’ capital and of cash flows present fairly, in all material respects, the financial position of Suburban Propane Partners, L.P. and its subsidiaries (the “Partnership”) at September 27, 2008 and September 29, 2007, and the results of their operations and their cash flows for each of the three years in the period ended September 27, 2008 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of September 27, 2008, 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 financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing in Item 9A. Our responsibility is to express opinions on these financial statements and on the Partnership’s internal control over financial reporting based on our integrated 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 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 (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) 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 (iii) 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.

PricewaterhouseCoopers LLP
Florham Park, New Jersey
November 26, 2008

F-2

SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)


	September 27,			September 29,
	2008			2007

ASSETS
Current assets:
Cash and cash equivalents	$	137,698		$	96,586
Accounts receivable, less allowance for doubtful accounts of $6,578 and $5,041, respectively		94,933			85,270
Inventories		79,822			81,246
Assets held for sale		—			11,221
Prepaid expenses and other current assets		47,098			21,551

Total current assets		359,551			295,874
Property, plant and equipment, net		367,808			374,641
Goodwill		276,282			277,559
Other intangible assets, net		16,018			18,242
Pension asset		132			5,547
Other assets		15,922			17,018

Total assets	$	1,035,713		$	988,881


LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	58,079		$	56,999
Accrued employment and benefit costs		27,053			37,640
Accrued insurance		41,120			13,880
Customer deposits and advances		71,206			75,394
Accrued interest		11,030			8,546
Liabilities associated with assets held for sale		—			1,291
Other current liabilities		15,127			12,261

Total current liabilities		223,615			206,011
Long-term borrowings		531,772			548,538
Postretirement benefits obligation		17,153			22,193
Accrued insurance		31,913			36,428
Other liabilities		11,184			9,434

Total liabilities		815,637			822,604


Commitments and contingencies

Partners’ capital:
Common Unitholders (32,725 and 32,674 units issued and outstanding at September 27, 2008 and September 29, 2007, respectively)		264,231			208,230
Deferred compensation		—			5,660
Common Units held in trust, at cost		—			(5,660	)
Accumulated other comprehensive loss		(44,155	)		(41,953	)

Total partners’ capital		220,076			166,277

Total liabilities and partners’ capital	$	1,035,713		$	988,881

The accompanying notes are an integral part of these consolidated financial statements.

F-3

SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit amounts)


	Year Ended
	September 27,			September 29,			September 30,
	2008			2007			2006
Revenues
Propane	$	1,132,950		$	1,019,798		$	1,081,573
Fuel oil and refined fuels		288,078			262,076			356,531
Natural gas and electricity		103,745			94,352			122,071
Services		44,393			56,519			87,258
All other		4,997			6,818			9,697

		1,574,163			1,439,563			1,657,130
Costs and expenses
Cost of products sold		1,039,436			865,418			1,051,797
Operating		308,071			322,852			373,305
General and administrative		48,134			56,422			63,561
Restructuring charges and severance costs		—			1,485			6,076
Depreciation and amortization		28,394			28,790			32,653

		1,424,035			1,274,967			1,527,392


Income before interest expense and provision for income taxes		150,128			164,596			129,738
Interest income		2,787			3,863			630
Interest expense		(39,839	)		(39,459	)		(41,310	)


Income before provision for income taxes		113,076			129,000			89,058
Provision for income taxes		1,903			5,653			764


Income from continuing operations		111,173			123,347			88,294
Discontinued operations:
Gain on disposal of discontinued operations		43,707			1,887			—
Income from discontinued operations		—			2,053			2,446


Net income	$	154,880		$	127,287		$	90,740


General Partner’s interest in net income	$	—		$	—		$	2,628

Limited Partners’ interest in net income	$	154,880		$	127,287		$	88,112


Income per Common Unit — basic
Income from continuing operations	$	3.39		$	3.79		$	2.76
Discontinued operations		1.33			0.12			0.08

Net income	$	4.72		$	3.91		$	2.84

Weighted average number of Common Units outstanding — basic		32,783			32,554			30,310


Income per Common Unit — diluted
Income from continuing operations	$	3.37		$	3.77		$	2.75
Discontinued operations		1.33			0.12			0.08

Net income	$	4.70		$	3.89		$	2.83

Weighted average number of Common Units outstanding — diluted		32,950			32,730			30,453

The accompanying notes are an integral part of these consolidated financial statements.

F-4

SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)


	Year Ended
	September 27,			September 29,			September 30,
	2008			2007			2006
Cash flows from operating activities:
Net income	$	154,880		$	127,287		$	90,740
Adjustments to reconcile net income to net cash provided by operations:
Depreciation expense — continuing operations		26,170			26,547			30,066
Depreciation expense — discontinued operations		—			452			498
Amortization of intangible assets		2,224			2,243			2,587
Amortization of debt origination costs		1,328			1,327			1,324
Compensation cost recognized under Restricted Unit Plan		2,156			3,014			2,221
Amortization of discount on long-term borrowings		234			234			234
Gain on disposal of property, plant and equipment, net		(2,252	)		(2,782	)		(1,000	)
Gain on disposal of discontinued operations		(43,707	)		(1,887	)		—
Pension settlement charge		—			3,269			4,437
Deferred tax provision		1,277			3,800			—
Changes in assets and liabilities
(Increase) decrease in accounts receivable		(9,663	)		(6,827	)		31,371
Decrease (increase) in inventories		1,424			(1,915	)		1,147
(Increase) decrease in prepaid expenses and other current assets		(27,001	)		(4,268	)		15,745
Increase (decrease) increase in accounts payable		1,080			(448	)		(6,197	)
(Decrease) increase in accrued employment and benefit costs		(10,587	)		3,551			15,384
Increase (decrease) in accrued insurance		27,240			6,520			(4,145	)
(Decrease) increase in customer deposits and advances		(4,188	)		12,780			531
Increase (decrease) in accrued interest		2,484			175			(2,604	)
Increase (decrease) in other accrued liabilities		2,866			(5,475	)		(7,711	)
Decrease (increase) in other noncurrent assets		2,810			(40,444	)		(44	)
(Decrease) increase in other noncurrent liabilities		(8,258	)		43,804			5,737
Contribution to defined benefit pension plan		—			(25,000	)		(10,000	)

Net cash provided by operating activities		120,517			145,957			170,321

Cash flows from investing activities:
Capital expenditures		(21,819	)		(26,756	)		(23,057	)
Proceeds from sale of property, plant and equipment		4,734			5,783			3,965
Proceeds from sale of discontinued operations		53,715			1,284			—

Net cash provided by (used in) investing activities		36,630			(19,689	)		(19,092	)

Cash flows from financing activities:
Long-term debt repayments		(15,000	)		—			(475	)
Short-term repayments		—			—			(26,750	)
Partnership distributions		(101,035	)		(90,253	)		(77,844	)

Net cash (used in) financing activities		(116,035	)		(90,253	)		(105,069	)

Net increase in cash and cash equivalents		41,112			36,015			46,160
Cash and cash equivalents at beginning of year		96,586			60,571			14,411

Cash and cash equivalents at end of year	$	137,698		$	96,586		$	60,571


Supplemental disclosure of cash flow information:
Cash paid for interest	$	35,217		$	37,165		$	41,241

The accompanying notes are an integral part of these consolidated financial statements.

F-5

SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(in thousands)



																		Accumulated
	Number of											Common						Other			Total
	Common		Common			General			Deferred			Units Held			Unearned			Comprehensive			Partners’			Comprehensive
	Units		Unitholders			Partner			Compensation			in Trust			Compensation			(Loss) Income			Capital			Income (Loss)

Balance at September 24, 2005		30,279	$	159,199		$	(1,779	)	$	5,887		$	(5,887	)	$	(4,355	)	$	(76,949	)	$	76,116

Net income				88,112			2,628															90,740		$	90,740
Other comprehensive income:
Net unrealized gains on cash flow hedges																			590			590			590
Non-cash pension settlement charge																			4,437			4,437			4,437
Minimum pension liability adjustment																			4,441			4,441			4,441

Total comprehensive income																								$	100,208

Partnership distributions				(75,026	)		(2,818	)														(77,844	)
Common Units issued under Restricted Unit Plan		35
Common Units distributed from trust										(183	)		183									—
Elimination of unearned compensation from adoption of SFAS 123R				(4,355	)											4,355						—
Compensation cost recognized under Restricted Unit Plan, net of forfeitures				2,221																		2,221

Balance at September 30, 2006		30,314	$	170,151		$	(1,969	)	$	5,704		$	(5,704	)	$	—		$	(67,481	)	$	100,701

Net income				127,287																		127,287		$	127,287
Other comprehensive income:
Net unrealized losses on cash flow hedges																			(173	)		(173	)		(173	)
Reclassification of realized losses on cash flow hedges into earnings																			1,967			1,967			1,967
Non-cash pension settlement charge																			3,269			3,269			3,269
Minimum pension liability adjustment																			63,510			63,510			63,510
Adjustment to initially adopt SFAS 158																			(43,045	)		(43,045	)		—

Total comprehensive income																								$	195,860


Partnership distributions				(90,253	)																	(90,253	)
Common Units issued under Restricted Unit Plan		60
Common Units issued in Exchange of GP interest		2,300		80,443																		80,443
Exchange and cancellation of GP Interest				(82,412	)		1,969															(80,443	)
Common Units distributed from trust										(44	)		44									—
Compensation cost recognized under Restricted Unit Plan, net of forfeitures				3,014																		3,014

Balance at September 29, 2007		32,674	$	208,230		$	—		$	5,660		$	(5,660	)	$	—		$	(41,953	)	$	166,277


Net income				154,880																		154,880		$	154,880
Other comprehensive income:
Net unrealized losses on cash flow hedges																			(2,916	)		(2,916	)		(2,916	)
Reclassification of realized gains on cash flow hedges into earnings																			(1,377	)		(1,377	)		(1,377	)
Amortization of net actuarial losses and prior service credits into earnings and net change in funded status of benefit plans																			2,091			2,091			2,091

Total comprehensive income																								$	152,678

Partnership distributions				(101,035	)																	(101,035	)
Common Units issued under Restricted Unit Plan		51
Common Units distributed from trust										(5,660	)		5,660									—
Compensation cost recognized under Restricted Unit Plan, net of forfeitures				2,156																		2,156

Balance at September 27, 2008		32,725	$	264,231		$	—		$	—		$	—		$	—		$	(44,155	)	$	220,076

The accompanying notes are an integral part of these consolidated financial statements.

F-6

SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(dollars in thousands, except per unit amounts)

1. Partnership Organization and Formation

Suburban Propane Partners, L.P. (the “Partnership”) is a publicly traded Delaware limited partnership principally engaged, through its operating partnership and subsidiaries, in the retail marketing and distribution of propane, fuel oil and refined fuels, as well as the marketing of natural gas and electricity in deregulated markets. In addition, to complement its core marketing and distribution businesses, the Partnership services a wide variety of home comfort equipment, particularly for heating and ventilation. The publicly traded limited partner interests in the Partnership are evidenced by common units traded on the New York Stock Exchange (“Common Units”), with 32,725,383 Common Units outstanding at September 27, 2008. The holders of Common Units are entitled to participate in distributions and exercise the rights and privileges available to limited partners under the Third Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”), adopted on October 19, 2006 following approval by Common Unitholders at the Partnership’s Tri-Annual Meeting and as thereafter amended by the Board of Supervisors on July 31, 2007, pursuant to the authority granted to the Board in the Partnership Agreement. Rights and privileges under the Partnership Agreement include, among other things, the election of all members of the Board of Supervisors and voting on the removal of the general partner.

Suburban Propane, L.P. (the “Operating Partnership”), a Delaware limited partnership, is the Partnership’s operating subsidiary formed to operate the propane business and assets. In addition, Suburban Sales & Service, Inc. (the “Service Company”), a subsidiary of the Operating Partnership, was formed to operate the service work and appliance and parts businesses of the Partnership. The Operating Partnership, together with its direct and indirect subsidiaries, accounts for substantially all of the Partnership’s assets, revenues and earnings. The Partnership, the Operating Partnership and the Service Company commenced operations in March 1996 in connection with the Partnership’s initial public offering.

The general partner of both the Partnership and the Operating Partnership is Suburban Energy Services Group LLC (the “General Partner”), a Delaware limited liability company. On October 19, 2006, the Partnership consummated an agreement with its General Partner to exchange 2,300,000 newly issued Common Units for the General Partner’s incentive distribution rights (“IDRs”) and the economic interest in the Partnership and the Operating Partnership included in the general partner interests therein (the “GP Exchange Transaction”). Prior to the GP Exchange Transaction, the General Partner was majority-owned by senior management of the Partnership and owned 224,625 general partner units (an approximate 0.74% ownership interest) in the Partnership and a 1.0101% general partner interest in the Operating Partnership. The General Partner also held all outstanding IDRs and appointed two of the five members of the Board of Supervisors. As a result of the GP Exchange Transaction, the General Partner no longer has any economic interest in either the Partnership or the Operating Partnership other than as a holder of 784 Common Units that will remain in the General Partner, no IDRs are outstanding and the sole member of the General Partner is the Partnership’s Chief Executive Officer.

On December 23, 2003, the Partnership acquired substantially all of the assets and operations of Agway Energy Products, LLC, Agway Energy Services, Inc. and Agway Energy Services PA, Inc. (collectively referred to as “Agway Energy”) pursuant to an asset purchase agreement dated November 10, 2003 (the “Agway Acquisition”). The operations of Agway Energy consisted of the distribution and marketing of propane, fuel oil and refined fuels, as well as the marketing of natural gas and electricity. The Partnership’s fuel oil and refined fuels, natural gas and electricity and services businesses are structured as corporate entities (collectively referred to as Corporate Entities) and, as such, are subject to corporate level income tax.

F-7

The Partnership serves over 900,000 active residential, commercial, industrial and agricultural customers from approximately 300 locations in 30 states. The Partnership’s operations are concentrated in the east and west coast regions of the United States, including Alaska. No single customer accounted for 10% or more of the Partnership’s revenues during fiscal 2008, 2007 or 2006. During fiscal 2008, 2007 and 2006, three suppliers provided approximately 35%, 34% and 35%, respectively, of the Partnership’s total propane supply. The Partnership believes that, if supplies from any of these three suppliers were interrupted, it would be able to secure adequate propane supplies from other sources without a material disruption of its operations.

2. Summary of Significant Accounting Policies

Principles of Consolidation. The consolidated financial statements include the accounts of the Partnership, the Operating Partnership and all of its direct and indirect subsidiaries. All significant intercompany transactions and account balances have been eliminated. As a result of the GP Exchange Transaction, the General Partner no longer has any economic interest in the Partnership or the Operating Partnership apart from 784 Common Units held by it. The Partnership consolidates the results of operations, financial condition and cash flows of the Operating Partnership as a result of the Partnership’s 100% limited partner interest in the Operating Partnership.

Fiscal Period. The Partnership’s fiscal year ends on the last Saturday nearest to September 30. Fiscal 2008 and fiscal 2007 included 52 weeks of operations and fiscal 2006 included 53 weeks of operations.

Revenue Recognition. Sales of propane, fuel oil and refined fuels are recognized at the time product is delivered to the customer. Revenue from the sale of appliances and equipment is recognized at the time of sale or when installation is complete, as applicable. Revenue from repairs, maintenance and other service activities is recognized upon completion of the service. Revenue from service contracts is recognized ratably over the service period. Revenue from the natural gas and electricity business is recognized based on customer usage as determined by meter readings, as adjusted for amounts delivered but unbilled at the end of each accounting period.

Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles (“GAAP”) 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 revenues and expenses during the reporting period. Estimates have been made by management in the areas of self-insurance and litigation reserves, pension and other postretirement benefit liabilities and costs, valuation of derivative instruments, depreciation and amortization of long-lived assets, asset impairment assessments, tax valuation allowances and allowances for doubtful accounts. Actual results could differ from those estimates, making it reasonably possible that a change in these estimates could occur in the near term.

Cash and Cash Equivalents. The Partnership considers all highly liquid instruments purchased with an original maturity of three months or less to be cash equivalents. The carrying amount approximates fair value because of the short maturity of these instruments.

Inventories. Inventories are stated at the lower of cost or market. Cost is determined using a weighted average method for propane, fuel oil and refined fuels and natural gas, and a standard cost basis for appliances, which approximates average cost.

F-8

Derivative Instruments and Hedging Activities.

Commodity Price Risk. Given the retail nature of its operations, the Partnership maintains a certain level of priced physical inventory to ensure its field operations have adequate supply commensurate with the time of year. The Partnership’s strategy is to keep its physical inventory priced relatively close to market for its field operations. The Partnership enters into a combination of exchange-traded futures and option contracts, forward contracts and, in certain instances, over-the-counter options (collectively, “derivative instruments”) to hedge price risk associated with propane and fuel oil physical inventory, as well as future purchases of propane or fuel oil used in its operations and to ensure adequate supply during periods of high demand. Under this risk management strategy, realized gains or losses on derivative instruments will typically offset losses or gains on the physical inventory once the product is sold. All of the Partnership’s derivative instruments are reported on the consolidated balance sheet, within other current assets or other current liabilities, at their fair values pursuant to Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended (“SFAS 133”). In addition, in the course of normal operations, the Partnership routinely enters into contracts such as forward priced physical contracts for the purchase or sale of propane and fuel oil that, under SFAS 133, qualify for and are designated as normal purchase or normal sale contracts. Such contracts are exempted from the fair value accounting requirements of SFAS 133 and are accounted for at the time product is purchased or sold under the related contract. The Partnership does not use derivative instruments for speculative trading purposes. Market risks associated with futures, options and forward contracts are monitored daily for compliance with the Partnership’s Hedging and Risk Management Policy which includes volume limits for open positions. Priced on-hand inventory is also reviewed and managed daily as to exposures to changing market prices.

On the date that futures, forward and option contracts are entered into, other than those designated as normal purchases or normal sales, the Partnership makes a determination as to whether the derivative instrument qualifies for designation as a hedge. Changes in the fair value of derivative instruments are recorded each period in current period earnings or other comprehensive income (loss) (“OCI”), depending on whether the derivative instrument is designated as a hedge and, if so, the type of hedge. For derivative instruments designated as cash flow hedges, the Partnership formally assesses, both at the hedge contract’s inception and on an ongoing basis, whether the hedge contract is highly effective in offsetting changes in cash flows of hedged items. Changes in the fair value of derivative instruments designated as cash flow hedges are reported in OCI to the extent effective and reclassified into cost of products sold during the same period in which the hedged item affects earnings. The mark-to-market gains or losses on ineffective portions of cash flow hedges used to hedge future purchases are recognized in cost of products sold immediately. Changes in the fair value of derivative instruments that are not designated as cash flow hedges, and that do not meet the normal purchase and normal sale exemption under SFAS 133, are recorded within cost of products sold as they occur. Cash flows associated with derivative instruments are reported as operating activities within the consolidated statement of cash flows.

Interest Rate Risk. A portion of the Partnership’s long-term borrowings bear interest at a variable rate based upon LIBOR, plus an applicable margin depending on the level of the Partnership’s total leverage (the ratio of total debt to EBITDA). Therefore, the Partnership is subject to interest rate risk on the variable component of the interest rate. The Partnership manages part of its variable interest rate risk by entering into interest rate swap agreements. The interest rate swap is being accounted for under SFAS 133 and the Partnership has designated the interest rate swap as a cash flow hedge. Changes in the fair value of the interest rate swap are recognized in OCI until the hedged item is recognized in earnings.

F-9

Long-Lived Assets. Long-lived assets include:

Property, plant and equipment. Property, plant and equipment are stated at cost. Expenditures for maintenance and routine repairs are expensed as incurred while betterments are capitalized as additions to the related assets and depreciated over the asset’s remaining useful life. The Partnership capitalizes costs incurred in the acquisition and modification of computer software used internally, including consulting fees and costs of employees dedicated solely to a specific project. At the time assets are retired, or otherwise disposed of, the asset and related accumulated depreciation are removed from the accounts, and any resulting gain or loss is recognized within operating expenses. Depreciation is determined under the straight-line method based upon the estimated useful life of the asset as follows:


Buildings		40 Years
Building and land improvements		20-40 Years
Transportation equipment		4-20 Years
Storage facilities		7-40 Years
Office equipment		5-10 Years
Tanks and cylinders		15-40 Years
Computer software		3-7 Years

The weighted average estimated useful life of the Partnership’s tanks and cylinders is approximately 25 years.

The Partnership reviews the recoverability of long-lived assets when circumstances occur that indicate that the carrying value of an asset may not be recoverable. Such circumstances include a significant adverse change in the manner in which an asset is being used, current operating losses combined with a history of operating losses experienced by the asset or a current expectation that an asset will be sold or otherwise disposed of before the end of its previously estimated useful life. Evaluation of possible impairment is based on the Partnership’s ability to recover the value of the asset from the future undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the expected undiscounted cash flows are less than the carrying amount of such asset, an impairment loss is recorded as the amount by which the carrying amount of an asset exceeds its fair value. The fair value of an asset will be measured using the best information available, including prices for similar assets or the result of using a discounted cash flow valuation technique.

Goodwill. Goodwill represents the excess of the purchase price over the fair value of net assets acquired. Goodwill is subject to an impairment review at a reporting unit level, on an annual basis in August of each year, or when an event occurs or circumstances change that would indicate potential impairment. The Partnership assesses the carrying value of goodwill at a reporting unit level based on an estimate of the fair value of the respective reporting unit. Fair value of the reporting unit is estimated using discounted cash flow analyses taking into consideration estimated cash flows in a ten-year projection period and a terminal value calculation at the end of the projection period. If the fair value of the reporting unit exceeds its carrying value, the goodwill associated with the reporting unit is not considered to be impaired. If the carrying value of the reporting unit exceeds its fair value, an impairment loss is recognized to the extent that the carrying amount of the associated goodwill, if any, exceeds the implied fair value of the goodwill.

Other Intangible Assets. Other intangible assets consist of customer lists, tradenames, non-compete agreements and leasehold interests. Customer lists and tradenames are amortized under the straight-line method over the estimated period for which the assets are expected to contribute to the future cash flows of the reporting entities to which they relate, ending periodically between fiscal years 2012 and 2019. Non-compete agreements are amortized under the straight-line method over the periods of the related agreements, ending in fiscal year 2009. Leasehold interests are amortized under the straight-line method over the shorter of the lease term or the useful life of the related assets, through fiscal 2025.

Accrued Insurance. Accrued insurance represents the estimated costs of known and anticipated or unasserted claims for self-insured liabilities related to general and product, workers’ compensation and automobile liability. Accrued insurance provisions for unasserted claims arising from unreported incidents are based on an analysis of historical claims data. For each claim, the Partnership records a provision up to the estimated amount of the probable claim utilizing actuarially determined loss development factors applied to actual claims data. The Partnership maintains insurance coverage such that its net exposure for insured claims is limited to the insurance deductible, claims above which are paid by the Partnership’s insurance carriers. For the portion of the estimated liability that exceeds insurance deductibles, the Partnership records an asset within other assets related to the amount of the liability expected to be covered by insurance. Claims are generally settled within five years of origination.

Customer Deposits and Advances. The Partnership offers different payment programs to its customers including the ability to prepay for usage and to make equal monthly payments on account under a budget payment plan. The Partnership establishes a liability within customer deposits and advances for amounts collected in advance of deliveries.

F-10

Environmental Reserves. The Partnership establishes reserves for environmental exposures when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated based upon the Partnership’s best estimate of costs associated with environmental remediation and ongoing monitoring activities. Accrued environmental reserves are exclusive of claims against third parties, and an asset is established where contribution or reimbursement from such third parties has been agreed and the Partnership is reasonably assured of receiving such contribution or reimbursement. Environmental reserves are not discounted.

Income Taxes. As discussed in Note 1, the Partnership structure consists of two limited partnerships, the Partnership and the Operating Partnership, and several Corporate Entities. For federal income tax purposes, as well as for state income tax purposes in the majority of the states in which the Partnership operates, the earnings attributable to the Partnership and the Operating Partnership are included in the tax returns of the individual partners. As a result, except for certain states that impose an income tax on partnerships, no income tax expense is reflected in the Partnership’s consolidated financial statements relating to the earnings of the Partnership and the Operating Partnership. The earnings attributable to the Corporate Entities are subject to federal and state income taxes. Net earnings for financial statement purposes may differ significantly from taxable income reportable to Common Unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under the Partnership Agreement.

Income taxes for the Corporate Entities are provided based on the asset and liability approach to accounting for income taxes. Under this method, deferred tax assets and liabilities are recognized for the expected future tax consequences of differences between the carrying amounts and the tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period when the change is enacted. A valuation allowance is recorded to reduce the carrying amounts of deferred tax assets when it is more likely than not that the full amount will not be realized.

Asset Retirement Obligations. SFAS No. 143, “Accounting for Asset Retirement Obligations,” (“SFAS 143”) and Financial Accounting Standards Board (“FASB”) Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (“FIN 47”) prescribes financial accounting and reporting standards for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The provisions of this statement apply to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of a long-lived asset, except for certain obligations of lessees. The Partnership has recognized asset retirement obligations for certain costs of contractually mandated removal of leasehold improvements and certain costs to remove and properly dispose of underground and aboveground fuel oil storage tanks.

The Partnership records a liability at fair value for the estimated cost to settle an asset retirement obligation at the time that liability is incurred, which is generally when the asset is purchased, constructed or leased. The Partnership records the liability, which is referred to as an asset retirement obligation, when it has a legal obligation, as defined in SFAS 143, to incur costs to retire the asset and when a reasonable estimate of the fair value of the liability can be made. If a reasonable estimate cannot be made at the time the liability is incurred, the Partnership records the liability when sufficient information is available to estimate the liability’s fair value.

Unit-Based Compensation. The Partnership accounts for unit-based compensation in accordance with the revised SFAS No. 123, “Share-Based Payment” (“SFAS 123R”) which was adopted by the Partnership effective for the quarter ended December 24, 2005, the first quarter of fiscal 2006. Prior to adoption, the Partnership accounted for unit-based compensation plans under the provisions of Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations and followed the disclosure only provision of SFAS No. 123, “Accounting for Stock-Based Compensation”. SFAS 123R requires the recognition of compensation cost over the respective service period for employee services received in exchange for an award of equity or equity-based compensation based on the grant date fair value of the award. SFAS 123R also requires the measurement of liability awards under an equity-based payment arrangement based on remeasurement of the award’s fair value at the conclusion of each interim and annual reporting period until the date of settlement, taking into consideration the probability that the performance conditions will be satisfied.

F-11

Costs and Expenses. The cost of products sold reported in the consolidated statements of operations represents the weighted average unit cost of propane, fuel oil and refined fuels, as well as the cost of natural gas and electricity sold, including transportation costs to deliver product from the Partnership’s supply points to storage or to the Partnership’s customer service centers. Cost of products sold also includes the cost of appliances, equipment and related parts sold or installed by the Partnership’s customer service centers computed on a basis that approximates the average cost of the products. Unrealized (non-cash) gains or losses from changes in the fair value of derivative instruments that are not designated as cash flow hedges are recorded in each reporting period within cost of products sold. Cost of products sold is reported exclusive of any depreciation and amortization as such amounts are reported separately within the consolidated statements of operations.

All other costs of operating the Partnership’s retail propane, fuel oil and refined fuels distribution and appliance sales and service operations, as well as the natural gas and electricity marketing business, are reported within operating expenses in the consolidated statements of operations. These operating expenses include the compensation and benefits of field and direct operating support personnel, costs of operating and maintaining the vehicle fleet, overhead and other costs of the purchasing, training and safety departments and other direct and indirect costs of operating the Partnership’s customer service centers.

All costs of back office support functions, including compensation and benefits for executives and other support functions, as well as other costs and expenses to maintain finance and accounting, treasury, legal, human resources, corporate development and the information systems functions are reported within general and administrative expenses in the consolidated statements of operations.

Net Income Per Unit. Subsequent to the GP Exchange Transaction, computations of earnings per Common Unit are performed in accordance with SFAS No. 128 “Earnings per Share” (“SFAS 128”). Prior to the GP Exchange Transaction, when the General Partner’s interest included IDRs in the Partnership, computations of earnings per Common Unit were performed in accordance with Emerging Issues Task Force (“EITF”) consensus 03-6 “Participating Securities and the Two-Class Method Under FAS 128” (“EITF 03-6”), when applicable. EITF 03-6 requires, among other things, the use of the two-class method of computing earnings per unit when participating securities exist. The two-class method is an earnings allocation formula that computes earnings per unit for each class of Common Unit and participating security according to distributions declared and the participating rights in undistributed earnings, as if all of the earnings were distributed to the limited partners and the General Partner (inclusive of the IDRs of the General Partner which were considered participating securities for purposes of the two-class method). Net income was allocated to the Common Unitholders and the General Partner in accordance with their respective Partnership ownership interests, after giving effect to any priority income allocations for incentive distributions allocated to the General Partner. For purposes of the computation of income per Common Unit for the year ended September 29, 2007, earnings that would have been allocated to the General Partner for the period prior to the GP Exchange Transaction were not significant.

Basic income per Common Unit for the years ended September 27, 2008 and September 29, 2007 was computed by dividing net income by the weighted average number of outstanding Common Units and restricted units granted under the 2000 Restricted Unit Plan to retirement-eligible grantees. Diluted income per Common Unit for the years ended September 27, 2008 and September 29, 2007 was computed by dividing net income by the weighted average number of outstanding Common Units and unvested restricted units granted under the 2000 Restricted Unit Plan.

Basic income per Common Unit for the year ended September 30, 2006 was computed by dividing the limited partners’ share of net income, calculated under the two-class method of computing earnings, by the weighted average number of outstanding Common Units. Net income was allocated to the Unitholders and the General Partner in accordance with their respective partnership ownership interests, after giving effect to any priority income allocations to the General Partner for IDRs. Following the GP Exchange Transaction consummated on October 19, 2006, the two-class method of computing income per Common Unit under EITF 03-6 was no longer applicable.

F-12

In computing diluted net income per Common Unit, weighted average units outstanding used to compute basic net income per Common Unit were increased by 166,308, 175,701 and 143,039 units for the years ended September 27, 2008, September 29, 2007 and September 30, 2006, respectively, to reflect the potential dilutive effect of the unvested restricted units outstanding using the treasury stock method.

Comprehensive Income. The Partnership reports comprehensive (loss) income (the total of net income and all other non-owner changes in partners’ capital) within the consolidated statement of partners’ capital. Comprehensive (loss) income includes unrealized gains and losses on derivative instruments accounted for as cash flow hedges, minimum pension liability adjustments (prior to the adoption of SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — An Amendment of FASB Statements No. 87, 88, 106 and 132R” (“SFAS 158”)) and changes in the funded status of pension and other postretirement benefit plans (subsequent to the adoption of SFAS 158).

Recently Issued Accounting Standards. In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”). SFAS 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. It also establishes a fair value hierarchy that prioritizes information used in developing assumptions when pricing an asset or liability. SFAS 157 is effective for fiscal years beginning after November 15, 2007, which is the Partnership’s 2009 fiscal year which began on September 28, 2008. In February of 2008, the FASB provided an elective one-year deferral of provisions of SFAS 157 for nonfinancial assets and nonfinancial liabilities that are only measured at fair value on a non-recurring basis. The adoption of SFAS 157 did not have a material effect on the Partnership’s consolidated financial position, results of operations and cash flows.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”). Under SFAS 159, entities may elect to measure specified financial instruments and warranty and insurance contracts at fair value on a contract-by-contract basis, with changes in fair value recognized in earnings each reporting period. SFAS 159 is effective for fiscal years beginning after November 15, 2007, which is the Partnership’s 2009 fiscal year which began on September 28, 2008. The Partnership did not elect the fair value measurement option; accordingly, the adoption of SFAS 159 did not have a material impact on its consolidated financial position, results of operations and cash flows.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements — an Amendment of ARB No. 51” (“SFAS 160”). SFAS 160 establishes accounting and reporting standards for noncontrolling interests in an entity’s subsidiary and alters the way the consolidated income statement is presented. SFAS 160 is effective for fiscal years beginning on or after December 15, 2008, which will be the Partnership’s 2010 fiscal year beginning September 27, 2009. As of September 27, 2008, all of the Partnership’s subsidiaries are wholly-owned; accordingly, the adoption of SFAS 160 should not have any impact on the Partnership’s consolidated financial position, results of operations and cash flows.

Also in December 2007, the FASB issued revised SFAS No. 141 “Business Combinations” (“SFAS 141R”). Among other things, SFAS 141R requires an entity to recognize acquired assets, liabilities assumed and any noncontrolling interest at their respective fair values as of the acquisition date, clarifies how goodwill involved in a business combination is to be recognized and measured, and requires the expensing of acquisition-related costs as incurred. SFAS 141R is effective for business combinations entered into in fiscal years beginning on or after December 15, 2008, which will be the Partnership’s 2010 fiscal year beginning September 27, 2009, with early adoption prohibited.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities — an Amendment of FASB Statement No. 133” (“SFAS 161”). SFAS 161 requires enhanced disclosures about an entity’s objectives for using derivative instruments and related hedged items, how those derivative instruments are accounted for under SFAS 133 and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. SFAS 161 is effective for financial statements for interim or annual periods beginning after November 15, 2008, which will be the second quarter of the Partnership’s 2009 fiscal year beginning December 28, 2008. Because it is only a disclosure standard, the adoption of SFAS 161 will not have a material effect on the Partnership’s consolidated financial position, results of operations and cash flows.

F-13

Reclassifications and Revisions. Certain prior period amounts have been reclassified to conform with the current period presentation. In addition, accounts receivable and customer deposits and advances as of September 29, 2007 were increased by $13,663 to reflect certain customer advances previously included in accounts receivable. Accrued employment and benefit costs were reduced and other liabilities were increased as of September 29, 2007 by $4,062 to reclassify the non-current portion of the accrued long-term incentive plan award liabilities.

3. Distributions of Available Cash

The Partnership makes distributions to its partners no later than 45 days after the end of each fiscal quarter of the Partnership in an aggregate amount equal to its Available Cash for such quarter. Available Cash, as defined in the Partnership Agreement, generally means all cash on hand at the end of the respective fiscal quarter less the amount of cash reserves established by the Board of Supervisors in its reasonable discretion for future cash requirements. These reserves are retained for the proper conduct of the Partnership’s business, the payment of debt principal and interest and for distributions during the next four quarters.

Prior to October 19, 2006, the General Partner had IDRs which represented an incentive for the General Partner to increase distributions to Common Unitholders in excess of the target quarterly distribution of $0.55 per Common Unit. With regard to the first $0.55 of quarterly distributions paid in any given quarter, 98.26% of the Available Cash was distributed to the Common Unitholders and 1.74% was distributed to the General Partner. With regard to the balance of quarterly distributions in excess of the $0.55 per Common Unit target distribution, 85% of the Available Cash was distributed to the Common Unitholders and 15% was distributed to the General Partner. As a result of the GP Exchange Transaction, the IDRs were cancelled and the General Partner is no longer entitled to receive any cash distributions in respect of its general partner interests. Accordingly, beginning with the quarterly distribution paid on November 14, 2006 in respect of the fourth quarter of fiscal 2006, 100% of all cash distributions are paid to holders of Common Units.

The following summarizes the quarterly distributions per Common Unit declared and paid in respect of each of the quarters in the three fiscal years in the period ended September 27, 2008:


	Fiscal		Fiscal		Fiscal
	2008		2007		2006

First Quarter	$	0.7625	$	0.6875	$	0.6125
Second Quarter		0.7750		0.7000		0.6125
Third Quarter		0.8000		0.7125		0.6375
Fourth Quarter		0.8050		0.7500		0.6625

On October 23, 2008, the Board of Supervisors declared a quarterly distribution of $0.805 per Common Unit, or $3.22 per Common Unit on an annualized basis, in respect of the fourth quarter of fiscal 2008, which was paid on November 10, 2008 to holders of record on November 3, 2008. This quarterly distribution included an increase of $0.005 per Common Unit, or $0.02 per Common Unit on an annualized basis, from the previous distribution rate established in July, 2008, and an increase of $0.055, or $0.22 on an annualized basis from the prior year-end distribution rate.

F-14

4. Selected Balance Sheet Information

Inventories consist of the following:


	As of
	September 27,		September 29,
	2008		2007

Propane and refined fuels	$	76,036	$	76,730
Natural gas		283		697
Appliances and related parts		3,503		3,819

	$	79,822	$	81,246

The Partnership enters into contracts to buy propane, fuel oil and natural gas for supply purposes. Such contracts generally have a term of one year subject to annual renewal, with costs based on market prices at the date of delivery.

Property, plant and equipment consist of the following:


	As of
	September 27,		September 29,
	2008		2007

Land and improvements	$	28,307	$	28,463
Buildings and improvements		77,833		76,261
Transportation equipment		35,033		36,016
Storage facilities		74,954		72,237
Equipment, primarily tanks and cylinders		463,332		451,689
Computer systems		41,796		37,474
Construction in progress		1,711		5,823

		722,966		707,963
Less: accumulated depreciation		355,158		333,322

	$	367,808	$	374,641

Depreciation expense from continuing operations for the years ended September 27, 2008, September 29, 2007 and September 30, 2006 amounted to $26,170, $26,547 and $30,066, respectively. Depreciation expense for the year ended September 30, 2006 included a non-cash charge of $1,094 related to an impairment of assets as a result of restructuring activities in that year. Depreciation expense from discontinued operations for the years ended September 27, 2008, September 29, 2007 and September 30, 2006 amounted to $0, $452 and $498, respectively.

5. Goodwill and Other Intangible Assets

The Partnership’s fiscal 2008, fiscal 2007 and fiscal 2006 annual goodwill impairment review resulted in no adjustments to the carrying amount of goodwill. During fiscal 2008 and fiscal 2007, the Partnership reversed $1,277 and $3,800 of the deferred tax asset valuation allowance, respectively, which was established through purchase accounting for the Agway Acquisition, as a reduction to goodwill. This adjustment resulted from the utilization of a portion of the net operating losses established in purchase accounting for the Agway Acquisition.

F-15

Other intangible assets, the majority of which were acquired in the Agway Acquisition, consist of the following:


	September 27,			September 29,
	2008			2007

Customer lists	$	22,316		$	22,316
Tradenames		1,499			1,499
Other		2,117			2,483

		25,932			26,298

Less: accumulated amortization
Customer lists		(8,632	)		(6,669	)
Tradenames		(712	)		(562	)
Other		(570	)		(825	)

		(9,914	)		(8,056	)

	$	16,018		$	18,242

During fiscal 2007, in a non-cash transaction, the Partnership disposed of nine customer service centers considered to be non-strategic in exchange for three customer service centers of another company located in Alaska. The Partnership relinquished assets with a fair value of approximately $4,000 and allocated this fair value among the assets received, including $2,450 to the customer list acquired and $1,550 to the property, plant and equipment acquired (primarily tanks and cylinders). This customer list will be amortized over a ten-year period. The Partnership reported a $1,002 gain within discontinued operations in the first quarter of fiscal 2007 for the amount by which the fair value of assets relinquished exceeded the carrying value of the assets relinquished.

Aggregate amortization expense related to other intangible assets for the years ended September 27, 2008, September 29, 2007 and September 30, 2006 was $2,224, $2,243 and $2,587, respectively. Aggregate amortization expense related to other intangible assets for each of the five succeeding fiscal years as of September 27, 2008 is as follows: 2009 — $2,220; 2010 — $2,205; 2011 — $2,205; 2012 — $2,205 and 2013 — $1,572.

6. Restructuring Charges and Severance Costs

Throughout fiscal 2006, the Partnership approved and initiated plans of reorganization to realign the field operations in an effort to streamline the operating footprint and to leverage the system infrastructure to achieve additional operational efficiencies and reduce costs, as well as to restructure its services business (collectively, the “Restructuring”). As a result of the Restructuring, the Partnership recorded a restructuring charge of $5,276 in fiscal 2006 related to severance and other employee benefits for approximately 325 positions eliminated and $800 related to exit costs, primarily lease termination costs, associated with a plan to exit certain activities of the HomeTown Hearth & Grill business. During fiscal 2007, payments for severance and other employee costs associated with the Restructuring totaled $1,621 and were charged against the reserves established. As of September 29, 2007, the reserve for severance and other employee benefits was fully utilized. As of September 27, 2008, the remaining reserve consists only of exit costs associated with the HomeTown Hearth & Grill business, which amounted to $183 and is expected to be utilized over the next twelve months.

For the year ended September 27, 2008, the Partnership did not record any restructuring charges. For the year ended September 29, 2007, the Partnership incurred severance charges of $1,485 associated with positions eliminated during fiscal 2007 unrelated to a specific plan of restructuring.

7. Income Taxes

For federal income tax purposes, as well as for state income tax purposes in the majority of the states in which the Partnership operates, the earnings attributable to the Partnership, as a separate legal entity, and the Operating Partnership are not subject to income tax at the partnership level. Rather, the taxable income or loss attributable to the Partnership, as a separate legal entity, and to the Operating Partnership, which may vary substantially from the income (loss) before income taxes reported by the Partnership in the consolidated statement of operations, are includable in the federal and state income tax returns of the individual partners. The aggregate difference in the basis of the Partnership’s net assets for financial and tax reporting purposes cannot be readily determined as the Partnership does not have access to information regarding each partner’s basis in the Partnership.

F-16

The earnings of the Corporate Entities that do not qualify under the Internal Revenue Code for partnership status are subject to federal and state income taxes. The Partnership’s fuel oil and refined fuels, natural gas and electricity and services business segments are structured as corporate entities and, as such, are subject to corporate level income tax. However, a number of those corporate entities have experienced operating losses in recent years and, as a result, a full valuation allowance has been provided against the deferred tax assets. As a result, at present, many of those Corporate Entities do not report a tax provision. The conclusion that a full valuation is necessary was based upon an analysis of all available evidence, both negative and positive at the balance sheet date, which, taken as a whole, indicates that it is more likely than not that sufficient future taxable income will not be available to utilize the Partnership’s deferred tax assets. Management’s periodic reviews include, among other things, the nature and amount of the taxable income and expense items, the expected timing when assets will be used or liabilities will be required to be reported and the reliability of historical profitability of businesses expected to provide future earnings. Furthermore, management considered tax-planning strategies it could use to increase the likelihood that the deferred tax assets will be realized.

The income tax provision of all the legal entities included in the Partnership’s consolidated statement of operations consists of the following:


	Year Ended
	September 27,		September 29,		September 30,
	2008		2007		2006

Current
Federal	$	73	$	474	$	196
State and local		553		1,379		568

		626		1,853		764

Deferred		1,277		3,800		—

	$	1,903	$	5,653	$	764

As a result of the calendar year 2007 profitability of the Partnership’s fuel oil and refined fuel business, the Partnership reported taxable income and, as a result, utilized net operating losses to offset the current cash tax liability. Utilization of these net operating losses resulted in a $1,277 deferred tax provision, and a corresponding reversal of a portion of the valuation allowance established in purchase accounting for the Agway Acquisition, which reduced goodwill.

F-17

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


	Year Ended
	September 27,			September 29,			September 30,
	2008			2007			2006

Income tax provision at federal statutory tax rate	$	39,577		$	45,149		$	31,170
Impact of Partnership income not subject to federal income taxes		(45,323	)		(39,459	)		(27,822	)
Permanent differences		1,240			(358	)		396
Change in valuation allowance		6,930			(1,583	)		(3,766	)
State income taxes		(572	)		1,379			568
Alternative minimum tax		53			447			196
Other, net		(2	)		78			22

Provision for income taxes — current and deferred	$	1,903		$	5,653		$	764

The components of net deferred taxes and the related valuation allowance using current enacted tax rates are as follows:


	As of
	September 27,			September 29,
	2008			2007
Deferred tax assets:
Net operating loss carryforwards	$	41,768		$	35,060
Allowance for doubtful accounts		1,428			964
Inventory		722			1,062
Intangible assets		1,127			775
Deferred revenue		1,787			1,710
Derivative instruments		92			188
AMT credit carryforward		646			644
Other accruals		2,083			3,403

Total deferred tax assets		49,653			43,806

Deferred tax liabilities:
Property, plant and equipment		758			510

Total deferred tax liabilities		758			510

Net deferred tax assets		48,895			43,296
Valuation allowance		(48,895	)		(43,296	)

Net deferred tax assets	$	—		$	—

Of the total valuation allowance as of September 27, 2008, $16,442 was established through purchase accounting for the Agway Acquisition in December 2003. To the extent that a reversal of a portion of the valuation allowance is warranted in the future, the reversal will be recorded as a reduction of goodwill.

As of September 27, 2008, the Partnership had tax loss carryforwards for federal income tax reporting purposes of approximately $102,261, which are available to offset future federal taxable income and expire between 2024 and 2028.

F-18

8. Long-Term Borrowings

Short-term and long-term borrowings consist of the following:


	As of
	September 27,		September 29,
	2008		2007
Senior Notes, 6.875%, due December 15, 2013, net of unamortized discount of $1,228 and $1,462, respectively	$	423,772	$	423,538
Term Loan, 6.29% to 7.16%, due March 31, 2010		110,000		125,000

		533,772		548,538
Less: current portion of Term Loan		2,000		—

	$	531,772	$	548,538

The Partnership and its subsidiary, Suburban Energy Finance Corporation, have issued $425,000 aggregate principal amount of Senior Notes (the “2003 Senior Notes”) with an annual interest rate of 6.875%. The Partnership’s obligations under the 2003 Senior Notes are unsecured and rank senior in right of payment to any future subordinated indebtedness and equally in right of payment with any future senior indebtedness. The 2003 Senior Notes are structurally subordinated to, which means they rank effectively behind, any debt and other liabilities of the Operating Partnership. The 2003 Senior Notes mature on December 15, 2013 and require semi-annual interest payments in June and December. The Partnership is permitted to redeem some or all of the 2003 Senior Notes any time on or after December 15, 2008 at redemption prices specified in the indenture governing the 2003 Senior Notes. In addition, in the event of a change of control of the Partnership, as defined in the 2003 Senior Notes, the Partnership must offer to repurchase the notes at 101% of the principal amount repurchased, if the holders of the notes exercise the right of repurchase.

The Operating Partnership has a revolving credit facility, the Third Amended and Restated Credit Agreement (the “Revolving Credit Agreement”), which expires on March 31, 2010. The Revolving Credit Agreement provides for a five-year $125,000 term loan facility (the “Term Loan”) and a separate working capital facility which provides available revolving borrowing capacity up to $175,000. In addition, under the third amendment to the Revolving Credit Agreement the Operating Partnership is authorized to incur additional indebtedness of up to $10,000 in connection with capital leases and up to $20,000 in short-term borrowings during the period from December 1 to April 1 in each fiscal year to provide additional working capital during periods of peak demand, if necessary.

Borrowings under the Revolving Credit Agreement, including the Term Loan, bear interest at a rate based upon LIBOR plus the applicable margin or the Federal Funds rate plus 1/2 of 1%. An annual facility fee ranging from 0.375% to 0.50%, based upon certain financial tests, is payable quarterly whether or not borrowings occur. As of September 27, 2008 and September 29, 2007, there were no borrowings outstanding under the working capital facility of the Revolving Credit Agreement and there have been no borrowings since April 2006.

The Revolving Credit Agreement and the 2003 Senior Notes both contain various restrictive and affirmative covenants applicable to the Operating Partnership and the Partnership, respectively, including (i) restrictions on the incurrence of additional indebtedness, and (ii) restrictions on certain liens, investments, guarantees, loans, advances, payments, mergers, consolidations, distributions, sales of assets and other transactions. Under the Revolving Credit Agreement, the Operating Partnership is required to maintain a leverage ratio (the ratio of total debt to EBITDA, as defined) of less than 4.0 to 1. In addition, the Operating Partnership is required to maintain an interest coverage ratio (the ratio of EBITDA to interest expense) of greater than 2.5 to 1 at the Partnership level. The Partnership and the Operating Partnership were in compliance with all covenants and terms of the 2003 Senior Notes and the Revolving Credit Agreement as of September 27, 2008.

Under the 2003 Senior Note indenture, the Partnership is generally permitted to make cash distributions equal to available cash, as defined, as of the end of the immediately preceding quarter, if no event of default exists or would exist upon making such distributions, and the Partnership’s consolidated fixed charge coverage ratio, as defined, is greater than 1.75 to 1.

F-19

Under the Revolving Credit Agreement, as long as no default exists or would result, the Partnership is permitted to make cash distributions not more frequently than quarterly in an amount not to exceed available cash, as defined, for the immediately preceding fiscal quarter.

Under the Revolving Credit Agreement, proceeds from the sale, transfer or other disposition of any asset of the Operating Partnership, other than the sale of inventory in the ordinary course of business, in excess of $15,000 must be used to acquire productive assets within twelve months of receipt of the proceeds. Any proceeds not used within twelve months of receipt to acquire productive assets must be used to prepay the outstanding principal of the Term Loan. On September 26, 2008, the Operating Partnership prepaid $15,000 on the Term Loan with the net proceeds from the sale of the Tirzah storage facility that were not expected to be used to acquire productive assets within twelve months of receipt. An additional $2,000 prepayment was made on November 10, 2008, representing the remaining amount to be prepaid from the net proceeds from the Tirzah Sale.

In connection with the Term Loan, the Operating Partnership also entered into an interest rate swap agreement with a notional amount of $125,000. In connection with the $15,000 prepayment of the Term Loan on September 26, 2008, the Operating Partnership also amended the interest rate swap contract to reduce the notional amount by $15,000. From the original borrowing date of March 31, 2005 through March 31, 2010, the Operating Partnership paid or will pay a fixed interest rate of 4.66% to the issuing lender on notional principal amount outstanding, effectively fixing the LIBOR portion of the interest rate at 4.66%. In return, the issuing lender paid or will pay to the Operating Partnership a floating rate, namely LIBOR, on the same notional principal amount. The applicable margin above LIBOR, as defined in the Revolving Credit Agreement, will be paid in addition to this fixed interest rate of 4.66%. The fair value of the interest rate swap amounted to $(3,200) and $(284) at September 27, 2008 and September 29, 2007, respectively, and is included in other liabilities with a corresponding amount included within accumulated other comprehensive loss.

Debt origination costs representing the costs incurred in connection with the placement of, and the subsequent amendment to, the 2003 Senior Notes and the Revolving Credit Agreement were capitalized within other assets and are being amortized on a straight-line basis because it is not materially different from the effective interest method over the term of the respective debt agreements. Other assets at September 27, 2008 and September 29, 2007 include debt origination costs with a net carrying amount of $4,902 and $6,230, respectively. Aggregate amortization expense related to deferred debt origination costs included within interest expense for the years ended September 27, 2008, September 29, 2007 and September 30, 2006 was $1,328, $1,327 and $1,324, respectively.

The aggregate amounts of long-term debt maturities subsequent to September 27, 2008 are as follows: 2009 — $2,000; 2010 — $108,000; 2011 — $0; 2012 — $0; and thereafter — $425,000.

9. Unit-Based Compensation Arrangements

As described in Note 2, the Partnership accounts for its unit-based compensation arrangements under SFAS 123R, which requires the recognition of compensation cost over the respective service period for employee services received in exchange for an award of equity or equity-based compensation based on the grant date fair value of the award, as well as the measurement of liability awards under a unit-based payment arrangement based on remeasurement of the award’s fair value at the conclusion of each quarterly reporting period until the date of settlement, taking into consideration the probability that the performance conditions will be satisfied. The Partnership has historically recognized unearned compensation associated with awards under its 2000 Restricted Unit Plan ratably to expense over the vesting period based on the fair value of the award on the grant date and has historically recognized compensation cost and the associated unearned compensation liability for equity-based awards under its Long-Term Incentive Plan consistent with the requirements of SFAS 123R.

F-20

2000 Restricted Unit Plan. In November 2000, the Partnership adopted the Suburban Propane Partners, L.P. 2000 Restricted Unit Plan (the “2000 Restricted Unit Plan”) which authorizes the issuance of Common Units to executives, managers and other employees and members of the Board of Supervisors of the Partnership. On October 17, 2006, the Partnership adopted amendments to the 2000 Restricted Unit Plan which, among other things, increased the number of Common Units authorized for issuance under the plan by 230,000 for a total of 717,805. Restricted units issued under the 2000 Restricted Unit Plan vest over time with 25% of the Common Units vesting at the end of each of the third and fourth anniversaries of the grant date and the remaining 50% of the Common Units vesting at the end of the fifth anniversary of the grant date. The 2000 Restricted Unit Plan participants are not eligible to receive quarterly distributions or vote their respective restricted units until vested. Restrictions also limit the sale or transfer of the units during the restricted periods. The value of the Restricted Unit is established by the market price of the Common Unit on the date of grant. Restricted units are subject to forfeiture in certain circumstances as defined in the 2000 Restricted Unit Plan. Compensation expense for the unvested awards is recognized ratably over the vesting periods and is net of estimated forfeitures.

The following is a summary of activity in the 2000 Restricted Unit Plan:


				Weighted Average
				Grant Date Fair
	Units			Value Per Unit
Outstanding September 24, 2005		273,778		$	29.17
Granted		120,365			26.51
Forfeited		(18,154	)		(30.04	)
Vested		(35,203	)		(24.85	)

Outstanding September 30, 2006		340,786		$	29.28
Granted		151,515			44.51
Forfeited		(47,023	)		(30.06	)
Vested		(62,188	)		(28.34	)

Outstanding September 29, 2007		383,090		$	28.85
Granted		125,912			35.19
Forfeited		(11,359	)		(27.17	)
Vested		(51,128	)		(30.52	)

Outstanding September 27, 2008		446,515		$	30.57

As of September 27, 2008, unrecognized compensation cost related to unvested restricted units awarded under the 2000 Restricted Unit Plan amounted to $6,603. Compensation cost associated with the unvested awards is expected to be recognized over a weighted-average period of 1.9 years. Compensation expense for the 2000 Restricted Unit Plan for years ended September 27, 2008, September 29, 2007 and September 30, 2006 was $2,156, $3,014 and $2,221, respectively.

Long-Term Incentive Plan. The Partnership has a non-qualified, unfunded long-term incentive plan for officers and key employees (“LTIP-2”) which provides for payment, in the form of cash, for an award of equity-based compensation at the end of a three-year performance period. The level of compensation earned under LTIP-2 is based on the market performance of the Partnership’s Common Units on the basis of total return to Unitholders (''TRU’’) compared to the TRU of a predetermined peer group composed of other publicly traded partnerships (master limited partnerships), as approved by the Compensation Committee of the Board of Supervisors, over the same three-year performance period. Compensation expense, which includes adjustments to previously recognized compensation expense for current period changes in the fair value of unvested awards, for the years ended September 27, 2008, September 29, 2007 and September 30, 2006 was $1,859, $5,977 and $1,249, respectively.

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10. Compensation Deferral Plan

The Compensation Deferral Plan provided eligible employees of the Partnership the ability to defer receipt of all or a portion of vested restricted units granted under a prior restricted unit award plan. These units were held in trust on behalf of the individuals. During the second quarter of fiscal 2008, the remaining 292,682 Common Units were distributed to the participants resulting in the satisfaction of the deferred compensation liability of $5,660, classified in partners’ capital and a corresponding reduction to common units held in trust, classified as a contra-equity balance within partners’ capital.

11. Employee Benefit Plans

Defined Contribution Plan. The Partnership has an employee Retirement Savings and Investment Plan (the “401(k) Plan”) covering most employees. Employer matching contributions relating to the 401(k) Plan are a percentage of the participating employees’ elective contributions. The percentage of the Partnership’s contributions are based on a sliding scale depending on the Partnership’s achievement of annual performance targets. These contributions totaled $1,190, $5,426 and $3,868 for the years ended September 27, 2008, September 29, 2007 and September 30, 2006, respectively.

Defined Benefit Pension Benefits and Retiree Health and Life Benefits.

Defined Benefit Pension Benefits. The Partnership has a noncontributory defined benefit pension plan which was originally designed to cover all eligible employees of the Partnership who met certain requirements as to age and length of service. Effective January 1, 1998, the Partnership amended its defined benefit pension plan to provide benefits under a cash balance formula as compared to a final average pay formula which was in effect prior to January 1, 1998. Effective January 1, 2000, participation in the defined benefit pension plan was limited to eligible existing participants on that date with no new participants eligible to participate in the plan. On September 20, 2002, the Board of Supervisors approved an amendment to the defined benefit pension plan whereby, effective January 1, 2003, future service credits ceased and eligible employees receive interest credits only toward their ultimate retirement benefit.

Contributions, as needed, are made to a trust maintained by the Partnership. Contributions to the defined benefit pension plan are made by the Partnership in accordance with the Employee Retirement Income Security Act of 1974 minimum funding standards plus additional amounts made at the discretion of the Partnership, which may be determined from time to time. There were no minimum funding requirements for the defined benefit pension plan for fiscal 2008, 2007 or 2006. In recent years, cash balance defined benefit pension plans have come under increased scrutiny resulting in litigation regarding such plans sponsored by other companies. Partly in response to these developments, the federal Pension Protection Act of 2006 (the “2006 Pension Act”) was recently enacted, and these developments may result in further legislative changes impacting cash balance defined benefit pension plans in the future. There can be no assurances that future legislative developments will not have an adverse effect on the Partnership’s results of operations or cash flows.

Retiree Health and Life Benefits. The Partnership provides postretirement health care and life insurance benefits for certain retired employees. Partnership employees hired prior to July 1993 are eligible for postretirement life insurance benefits if they reach a specified retirement age while working for the Partnership. Partnership employees hired prior to July 1993 and who retired prior to March 1998 are eligible for postretirement health care benefits if they reached a specified retirement age while working for the Partnership. Effective January 1, 2000, the Partnership terminated its postretirement health care benefit plan for all eligible employees retiring after March 1, 1998. All active employees who were eligible to receive health care benefits under the postretirement plan subsequent to March 1, 1998, were provided an increase to their accumulated benefits under the cash balance pension plan. The Partnership’s postretirement health care and life insurance benefit plans are unfunded. Effective January 1, 2006, the Partnership changed its postretirement health care plan from a self-insured program to one that is fully insured under which the Partnership pays a portion of the insurance premium on behalf of the eligible participants. This modification to the postretirement health care plan reduced the accumulated benefit obligation as of September 30, 2006 by $5,133 and resulted in a reduction of the net periodic postretirement benefit expense by approximately $637 for the year ended September 30, 2006.

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In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — An Amendment of FASB Statements No. 87, 88, 106 and 132R” (“SFAS 158”). SFAS 158 requires companies to recognize the funded status of pension and other postretirement benefit plans as an asset or liability on sponsoring employers’ balance sheets and to recognize changes in the funded status in comprehensive income (loss) in the year the changes occur. This statement also requires the measurement date of plan assets and obligations to occur at the end of the employer’s fiscal year. The Partnership uses the date of its consolidated financial statements as the measurement date.

The initial impact of adopting SFAS 158 is to recognize in accumulated other comprehensive income (loss) unrecognized prior service costs or credits and net actuarial gains or losses that were previously unrecognized under SFAS No. 87, “Employers’ Accounting for Pension” (“SFAS 87”). SFAS 158 became effective for the Partnership’s fiscal year ended September 29, 2007. The following table summarizes the effect of required changes in the additional minimum liability (“AML”) reported in accumulated other comprehensive loss as of September 29, 2007 prior to the adoption of SFAS 158, as well as the initial impact of the adoption of SFAS 158. The AML under SFAS 87 was eliminated during fiscal 2007, primarily as a result of employer contributions.


			AML Adjustments
	Prior to AML and		Prior to						Post AML and
	SFAS 158		SFAS 158			SFAS 158			SFAS 158
	Adjustments		Adoption			Adoption			Adjustments

Accrued pension liability (asset)	$	9,990	$	(63,510	)	$	47,973		$	(5,547	)
Accrued postretirement liability	$	29,353	$	—		$	(4,928	)	$	24,425
Accumulated other comprehensive loss	$	63,510	$	(63,510	)	$	43,045		$	43,045

Projected Benefit Obligation, Fair Value of Plan Assets and Funded Status. The following tables provide a reconciliation of the changes in the benefit obligations and the fair value of the plan assets for each of the years ended September 27, 2008 and September 29, 2007 and a statement of the funded status for both years using an end of year measurement date. Under the Partnership’s defined benefit pension plan, the accumulated benefit obligation and the projected benefit obligation are the same.

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							Retiree Health and Life
	Pension Benefits						Benefits
	2008			2007			2008			2007
Reconciliation of benefit obligations:
Benefit obligation at beginning of year	$	158,317		$	173,480		$	24,426		$	25,030
Service cost		—			—			8			12
Interest cost		8,749			8,905			1,399			1,317
Plan amendments		—			—			—			—
Actuarial (gain) loss		(16,904	)		(5,042	)		(4,954	)		110
Settlement payments		(6,653	)		(10,786	)		—			—
Benefits paid		(8,314	)		(8,240	)		(1,803	)		(2,043	)

Benefit obligation at end of year	$	135,195		$	158,317		$	19,076		$	24,426


Reconciliation of fair value of plan assets:
Fair value of plan assets at beginning of year	$	163,864		$	142,394		$	—		$	—
Actual return on plan assets		(13,570	)		15,496			—			—
Employer contributions		—			25,000			1,803			2,043
Settlement payments		(6,653	)		(10,786	)		—			—
Benefits paid		(8,314	)		(8,240	)		(1,803	)		(2,043	)

Fair value of plan assets at end of year	$	135,327		$	163,864		$	—		$	—


Funded status:
Funded status at end of year	$	132		$	5,547		$	(19,076	)	$	(24,426	)


Amounts recognized in consolidated balance sheets consist of:
Pension asset	$	132		$	5,547		$	—		$	—
Accrued benefit liability		—			—			(19,076	)		(24,426	)

Net amount recognized at end of year	$	132		$	5,547		$	(19,076	)	$	(24,426	)

Less: Current portion								1,923			2,233

Non-current benefit liability							$	(17,153	)	$	(22,193	)


Amounts not yet recognized in net periodic benefit cost and included in accumulated other comprehensive income (loss):
Actuarial net loss (gain)	$	50,345		$	47,973		$	(5,563	)	$	(610	)
Prior service (credits)		—			—			(3,828	)		(4,318	)

Net amount recognized in accumulated other comprehensive loss	$	50,345		$	47,973		$	(9,391	)	$	(4,928	)

The amounts in accumulated other comprehensive loss as of September 27, 2008 that are expected to be recognized as components of net periodic benefit costs during the next fiscal year are $4,050 and ($822) for pension and postretirement benefits, respectively.

During fiscal 2007, lump sum pension benefit payments to either terminated or retiring individuals amounted to $10,786, which exceeded the settlement threshold (combined service and interest costs of net periodic pension cost) of $8,905 for fiscal 2007, and as a result, the Partnership was required to recognize a non-cash settlement charge of $3,269 during the fourth quarter of fiscal 2007 pursuant to SFAS No. 88 “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits”. The non-cash charge was required to accelerate recognition of a portion of cumulative unrecognized losses in the defined benefit pension plan. During fiscal 2008, the amount of the pension benefit obligation settled through lump sum payments was $6,653, which did not exceed the settlement threshold of $8,749; therefore, a settlement charge was not required to be recognized for fiscal 2008.

F-24

The Partnership made a voluntary contribution of $25,000 to the defined benefit pension plan during fiscal 2007 to proactively improve the funded status of the plan. As of September 27, 2008 and September 29, 2007, the fair value of plan assets exceeded the projected benefit obligation of the defined benefit pension plan by $132 and $5,547, respectively, which was recognized on the balance sheet as an asset.

Plan Asset Allocation. The following table presents the actual allocation of assets held in trust as of September 27, 2008 and September 29, 2007:


	2008			2007

Fixed income securities — long-term bonds		81	%		80	%
Equity securities — domestic and international		19	%		20	%

		100	%		100	%

The Partnership’s investment policies and strategies, as set forth in the Investment Management Policy and Guidelines, are monitored by a Benefits Committee comprised of five members of management. During fiscal 2007, the Benefits Committee proposed and the Board of Supervisors approved contributions to the plan in order to fully fund the accumulated benefit obligation and to change the plan’s asset allocation to reduce investment risk and more closely match the asset mix to the future cash requirements of the plan. The implementation of this strategy resulted in the $25,000 voluntary contribution described above, and a change in the asset allocation to reflect a greater concentration of fixed income securities. The fixed income portion is invested in a combination of long-term U.S. government bonds and intermediate-term corporate bonds with a strategy to match the actuarially estimated duration of the plan’s projected benefit obligations. The target asset mix is as follows: (i) fixed income securities portion of the portfolio should range between 75% and 85%; and (ii) equity securities portion of the portfolio should range between 15% and 25%.

Projected Contributions and Benefit Payments. There are no projected minimum funding requirements under the Partnership’s defined benefit pension plan for fiscal 2009. Estimated future benefit payments for both pension and retiree health and life benefits are as follows:


			Retiree
			Health and
	Pension		Life
Fiscal Year	Benefits		Benefits
2009	$	19,878	$	1,923
2010		13,613		1,879
2011		12,868		1,820
2112		12,911		1,755
2013		12,269		1,672
2014 through 2018		55,271		6,965

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Effect on Operations. The following table provides the components of net periodic benefit costs included in operating expenses for the years ended September 27, 2008, September 29, 2007 and September 30, 2006:


	Pension Benefits									Retiree Health and Life Benefits
	2008			2007			2006			2008			2007			2006

Service cost	$	—		$	—		$	—		$	8		$	12		$	15
Interest cost		8,749			8,905			9,146			1,399			1,317			1,416
Expected return on plan assets		(9,082	)		(10,317	)		(10,294	)		—			—			—
Amortization of prior service credit		—			—			—			(490	)		(597	)		(1,083	)
Settlement charge		—			3,269			4,437			—			—			—
Recognized net actuarial loss		3,375			5,315			6,469			—			—			—

Net periodic benefit costs	$	3,042		$	7,172		$	9,758		$	917		$	732		$	348

Actuarial Assumptions. The assumptions used in the measurement of the Partnership’s benefit obligations as of September 27, 2008 and September 29, 2007 are shown in the following table:

Retiree Health and

Pension Benefits

Life Benefits

2008

2007

2008

2007

Weighted-average discount rate

7.625

6.000

7.625

6.000

Average rate of compensation increase

n/a

The assumptions used in the measurement of net periodic pension benefit and postretirement benefit costs for the years ended September 27, 2008, September 29, 2007 and September 30, 2006 are shown in the following table:


	Pension Benefits									Retiree Health and Life Benefits
	2008			2007			2006			2008			2007			2006

Weighted-average discount rate		6.00	%		5.50	%		5.25	%		6.00	%		5.50	%		5.25	%
Average rate of compensation increase		n/a			n/a			n/a			n/a			n/a			n/a
Weighted-average expected long- term rate of return on plan assets		6.00	%		8.00	%		8.00	%		n/a			n/a			n/a
Health care cost trend		n/a			n/a			n/a			9.50	%		10.00	%		10.00	%

The discount rate assumption takes into consideration current market expectations related to long-term interest rates and the projected duration of the Partnership’s pension obligations based on a benchmark index with similar characteristics as the expected cash flow requirements of the Partnership’s defined benefit pension plan over the long-term. The expected long-term rate of return on plan assets assumption reflects estimated future performance in the Partnership’s pension asset portfolio considering the investment mix of the pension asset portfolio and historical asset performance. 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. The market-related value of pension plan assets is the fair value of the assets. Unrecognized actuarial gains and losses in excess of 10% of the greater of the projected benefit obligation and the market-related value of plan assets are amortized over the expected average remaining service period of active employees expected to receive benefits under the plan.

The 9.50% increase in health care costs assumed at September 27, 2008 is assumed to decrease gradually to 5.00% in fiscal 2017 and to remain at that level thereafter. Increasing the assumed health care cost trend rates by 1.0% in each year would increase the Partnership’s benefit obligation as of September 27, 2008 by approximately $369 and the aggregate of service and interest components of net periodic postretirement benefit expense for the year ended September 27, 2008 by approximately $22. Decreasing the assumed health care cost trend rates by 1.0% in each year would decrease the Partnership’s benefit obligation as of September 27, 2008 by approximately $338 and the aggregate of service and interest components of net periodic postretirement benefit expense for the year ended September 27, 2008 by approximately $20. The Partnership has concluded that the prescription drug benefits within the retiree medical plan will not qualify for a Medicare subsidy available under recent legislation.

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12. Financial Instruments

Derivative Instruments and Hedging Activities.

Commodity Price Risk

The Partnership purchases propane and refined fuels that are eventually sold to its customers at various times, quantities and prices, exposing the Partnership to market fluctuations in the price of these commodities. A control environment has been established which includes policies and procedures for risk assessment and the approval, reporting and monitoring of derivative instruments and hedging activities. The Partnership closely monitors the potential impacts of commodity price changes and, where appropriate, utilizes commodity futures, forward and option contracts to hedge its commodity price risk, both to protect margins and to ensure supply during periods of high demand. Derivative instruments are used to hedge a portion of the Partnership’s forecasted purchases for no more than one year in the future. At September 27, 2008, the fair value of derivative instruments described above resulted in derivative assets of $5,048 included within prepaid expenses and other current assets and derivative liabilities of $494 included within other current liabilities. As of September 27, 2008, none of the Partnership’s outstanding commodity derivative instruments were designated as hedges for accounting purposes.

Unrealized gains and losses attributable to the mark-to-market adjustments on derivative instruments not designated as hedges under SFAS 133 are reported within cost of products sold for all periods presented. For the years ended September 27, 2008, September 29, 2007 and September 30, 2006, cost of products sold included unrealized gains (losses) in the amount of $1,764, ($7,555) and $14,472, respectively, attributable to changes in the fair value of derivative instruments not designated as hedges.

Interest Rate Risk

As of September 27, 2008, an unrealized loss of $2,916 was included in OCI attributable to the Partnership’s interest rate swap agreement and is expected to be recognized in earnings as the interest on the Term Loan impacts earnings through March 31, 2010. However, due to changes in the interest rate environment, the corresponding value in OCI is subject to change prior to its impact on earnings.

Credit Risk. The Partnership’s principal customers are residential and commercial end users of propane and fuel oil and refined fuels served by approximately 300 locations in 30 states. No single customer accounted for more than 10% of revenues during fiscal 2008, 2007 or 2006 and no concentration of receivables exists as of September 27, 2008 or September 29, 2007.

Exchange traded futures and options contracts are traded on and guaranteed by the New York Mercantile Exchange (the “NYMEX”) and as a result, have minimal credit risk. Futures contracts traded with brokers of the NYMEX require daily cash settlements in margin accounts. The Partnership is subject to credit risk with forward and option contracts entered into with various third parties to the extent the counterparties do not perform. The Partnership evaluates the financial condition of each counterparty with which it conducts business and establishes credit limits to reduce exposure to credit risk based on non-performance. The Partnership does not require collateral to support the contracts.

Fair Value of Financial Instruments. The fair value of cash and cash equivalents is not materially different from their carrying amounts because of the short-term nature of these instruments. The fair value of the Revolving Credit Agreement approximates the carrying value since the interest rates are periodically adjusted to reflect market conditions. Based upon quoted market prices of the 6.875% Senior Notes due December 15, 2013, the fair value of the Partnership’s 2003 Senior Notes was $386,750 as of September 27, 2008.

F-27

13. Commitments and Contingencies

Commitments. The Partnership leases certain property, plant and equipment, including portions of the Partnership’s vehicle fleet, for various periods under noncancelable leases. Rental expense under operating leases was $17,739, $19,611 and $27,217 for the years ended September 27, 2008, September 29, 2007 and September 30, 2006, respectively.

Future minimum rental commitments under noncancelable operating lease agreements as of September 27, 2008 are as follows:


	Minimum
	Lease
	Payments
Fiscal Year
2009	$	13,286
2010		10,409
2011		7,767
2012		5,732
2013 and thereafter		8,452

Contingencies.

Self Insurance. As discussed in Note 2, the Partnership is self-insured for general and product, workers’ compensation and automobile liabilities up to predetermined amounts above which third party insurance applies. At September 27, 2008 and September 29, 2007, the Partnership had accrued liabilities of $73,033 and $50,308, respectively, representing the total estimated losses under these self-insurance programs. The Partnership is also involved in various legal actions which have arisen in the normal course of business, including those relating to commercial transactions and product liability. Management believes, based on the advice of legal counsel, that the ultimate resolution of these matters will not have a material adverse effect on the Partnership’s financial position or future results of operations, after considering its self-insurance liability for known and unasserted self-insurance claims. For the portion of the estimated liability that exceeds insurance deductibles, the Partnership records an asset within other assets (or prepaid expenses and other current assets, as applicable) related to the amount of the liability expected to be covered by insurance which amounted to $38,825 and $13,858 as of September 27, 2008 and September 29, 2007, respectively.

During the first quarter of fiscal 2009, the Partnership agreed to settle a litigation involving alleged product liability for approximately $30,000. This settlement will be finalized once certain procedural activities are completed in various jurisdictions, which is expected to occur in the first quarter of fiscal 2009. The matter was settled through insurance above the level of the Partnership’s deductible. As a result of this settlement, in which the Partnership denied any liability, the Partnership increased the portion of its estimated self-insurance liability that exceeded the insurance deductible and established a corresponding asset of $30,000 as of September 27, 2008 to accrue for the settlement and subsequent reimbursement from the Partnership’s third party insurance carrier.

Environmental. The Partnership is subject to various federal, state and local environmental, health and safety laws and regulations. Generally, these laws impose limitations on the discharge of pollutants and establish standards for the handling of solid and hazardous wastes. These laws include the Resource Conservation and Recovery Act, the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), the Clean Air Act, the Occupational Safety and Health Act, the Emergency Planning and Community Right to Know Act, the Clean Water Act and comparable state statutes. CERCLA, also known as the “Superfund” law, imposes joint and several liability 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. Propane is not a hazardous substance within the meaning of CERCLA. However, the Partnership owns real property where such hazardous substances may exist.

F-28

The Partnership is also subject to various laws and governmental regulations concerning environmental matters and expects that it will be required to expend funds to participate in the remediation of certain sites, including sites where it has been designated by the Environmental Protection Agency as a potentially responsible party under CERCLA and at sites with aboveground and underground fuel storage tanks.

With the Agway Acquisition, the Partnership acquired certain surplus properties with either known or probable environmental exposure, some of which are currently in varying stages of investigation, remediation or monitoring. Additionally, the Partnership identified that certain active sites acquired contained environmental conditions which may require further investigation, future remediation or ongoing monitoring activities. The environmental exposures include instances of soil and/or groundwater contamination associated with the handling and storage of fuel oil, gasoline and diesel fuel.

Estimating the extent of the Partnership’s responsibility at a particular site, and the method and ultimate cost of remediation of that site, requires making numerous assumptions. As a result, the ultimate cost to remediate any site may differ from current estimates, and will depend, in part, on whether there is additional contamination, not currently known to the Partnership, at that site. However, management believes that the Partnership’s past experience provides a reasonable basis for estimating these liabilities. As additional information becomes available, estimates are adjusted as necessary. While management does not anticipate that any such adjustment would be material to the Partnership’s financial statements, the result of ongoing or future environmental studies or other factors could alter this expectation and require recording additional liabilities. Management currently cannot determine whether the Partnership will incur additional liabilities or the extent or amount of any such liabilities. As of September 27, 2008 and September 29, 2007, the environmental reserve amounted to $1,558 and $2,578, respectively.

Future developments, such as stricter environmental, health or safety laws and regulations thereunder, could affect the Partnership’s operations. Management does not anticipate that the cost of the Partnership’s compliance with environmental, health and safety laws and regulations, including CERCLA, as currently in effect and applicable to known sites will have a material adverse effect on the Partnership’s financial condition or results of operations. To the extent there are any environmental liabilities presently unknown to the Partnership or environmental, health or safety laws or regulations are made more stringent, however, there can be no assurance that the Partnership’s financial condition or results of operations will not be materially and adversely affected.

Legal Matters. Following the Operating Partnership’s 1999 acquisition of the propane assets of SCANA Corporation (“SCANA”), Heritage Propane Partners, L.P. had brought an action against SCANA for breach of contract and fraud and against the Operating Partnership for tortious interference with contract and tortious interference with prospective contract. On October 21, 2004, the jury returned a unanimous verdict in favor of the Operating Partnership on all claims, but against SCANA. After the jury returned the verdict against SCANA, the Operating Partnership filed a cross-claim against SCANA for indemnification, seeking to recover defense costs. On November 2, 2006, SCANA and the Operating Partnership reached a settlement agreement wherein the Operating Partnership received $2,000 as a reimbursement of defense costs incurred as a result of the lawsuit. The $2,000 was recorded as a reduction to general and administrative expenses during the first quarter of fiscal 2007.

14. Guarantees

The Partnership has residual value guarantees associated with certain of its operating leases, related primarily to transportation equipment, with remaining lease periods scheduled to expire periodically through fiscal 2015. Upon completion of the lease period, the Partnership guarantees that the fair value of the equipment will equal or exceed the guaranteed amount, or the Partnership will pay the lessor the difference. Although the fair value of equipment at the end of its lease term has historically exceeded the guaranteed amounts, the maximum potential amount of aggregate future payments the Partnership could be required to make under these leasing arrangements, assuming the equipment is deemed worthless at the end of the lease term, is approximately $16,058. The fair value of residual value guarantees for outstanding operating leases was de minimis as of September 27, 2008 and September 29, 2007.

F-29

15. Discontinued Operations and Disposition

The Partnership continuously evaluates its existing operations to identify opportunities to optimize the return on assets employed and selectively divests operations in slower growing or non-strategic markets and seeks to reinvest in markets that are considered to present more opportunities for growth. In line with that strategy, on October 2, 2007, the Operating Partnership completed the sale of its Tirzah, South Carolina underground granite propane storage cavern, and associated 62-mile pipeline, for $53,715 in cash, after taking into account certain adjustments. The 57.5 million gallon underground storage cavern is connected to the Dixie Pipeline and provides propane storage for the eastern United States. As part of the agreement, the Operating Partnership entered into a long-term storage arrangement, not to exceed 7 million propane gallons, with the purchaser of the cavern that will enable the Operating Partnership to continue to meet the needs of its retail operations, consistent with past practices. As a result of this sale, a gain of $43,707 was reported as a gain from the disposal of discontinued operations in the Partnership’s results for the first quarter of fiscal 2008. The results of operations from the Tirzah facilities in the comparative prior year periods have been reclassified to discontinued operations on the consolidated statements of operations for the fiscal years ended September 29, 2007 and September 30, 2006, and the assets and liabilities were classified as held for sale on the consolidated balance sheet as of September 29, 2007.

During the first quarter of fiscal 2007, in a non-cash transaction, the Partnership completed a transaction in which it disposed of nine customer service centers considered to be non-strategic in exchange for three customer service centers of another company located in Alaska. The Partnership reported a $1,002 gain within discontinued operations in the first quarter of fiscal 2007 for the amount by which the fair value of assets relinquished exceeded the carrying value of the assets relinquished. During the second half of fiscal 2007, the Partnership sold three customer service centers for net cash proceeds of $1,284 and reported a gain of $885 on disposal of discontinued operations. Prior period results of operations attributable to these customer service centers were not significant and, as such, have not been reclassified as discontinued operations.

16. Segment Information

The Partnership manages and evaluates its operations in six segments, four of which are reportable segments: Propane, Fuel Oil and Refined Fuels, Natural Gas and Electricity, and Services. The chief operating decision maker evaluates performance of the operating segments using a number of performance measures, including gross margins and income before interest expense and provision for income taxes (operating profit). Costs excluded from these profit measures are captured in Corporate and include corporate overhead expenses not allocated to the operating segments. Unallocated corporate overhead expenses include all costs of back office support functions that are reported as general and administrative expenses within the consolidated statements of operations. In addition, certain costs associated with field operations support that are reported in operating expenses within the consolidated statements of operations, including purchasing, training and safety, are not allocated to the individual operating segments. Thus, operating profit for each operating segment includes only the costs that are directly attributable to the operations of the individual segment. The accounting policies of the operating segments are the same as those described in the summary of significant accounting policies in Note 2.

The propane segment is primarily engaged in the retail distribution of propane to residential, commercial, industrial and agricultural customers and, to a lesser extent, wholesale distribution to large industrial end users. In the residential and commercial markets, propane is used primarily for space heating, water heating, cooking and clothes drying. Industrial customers use propane generally as a motor fuel burned in internal combustion engines that power over-the-road vehicles, forklifts and stationary engines, to fire furnaces and as a cutting gas. In the agricultural markets, propane is primarily used for tobacco curing, crop drying, poultry brooding and weed control.

The fuel oil and refined fuels segment is primarily engaged in the retail distribution of fuel oil, diesel, kerosene and gasoline to residential and commercial customers for use primarily as a source of heat in homes and buildings.

F-30

The natural gas and electricity segment is engaged in the marketing of natural gas and electricity to residential and commercial customers in the deregulated energy markets of New York and Pennsylvania. Under this operating segment, the Partnership owns the relationship with the end consumer and has agreements with the local distribution companies to deliver the natural gas or electricity from the Partnership’s suppliers to the customer.

The services segment is engaged in the sale, installation and servicing of a wide variety of home comfort equipment and parts, particularly in the areas of heating and ventilation. In furtherance of the Partnership’s efforts to restructure its field operations and to focus on its core operating segments, during fiscal 2006 the Partnership initiated plans to streamline the service offerings by significantly reducing installation activities and focusing on service offerings that support the Partnership’s existing customer base within its propane, refined fuels and natural gas and electricity segments.

For the year ended September 30, 2006, income before interest expense and provision for income taxes for the propane, fuel oil and refined fuels, services and all other segments included restructuring charges of $2,802, $500, $1,854 and $920, respectively. In addition, depreciation and amortization expense for the propane and all other segments for the year ended September 30, 2006 reflected non-cash charges of $187 and $907, respectively, for the impairment of fixed assets.

F-31

The following table presents certain data by reportable segment and provides a reconciliation of total operating segment information to the corresponding consolidated amounts for the periods presented:


	Year Ended
	September 27,			September 29,			September 30,
	2008			2007			2006
Revenues:
Propane	$	1,132,950		$	1,019,798		$	1,081,573
Fuel oil and refined fuels		288,078			262,076			356,531
Natural gas and electricity		103,745			94,352			122,071
Services		44,393			56,519			87,258
All other		4,997			6,818			9,697

Total revenues	$	1,574,163		$	1,439,563		$	1,657,130


Income (loss) before interest expense and provision for income taxes:
Propane	$	219,546		$	207,269		$	184,845
Fuel oil and refined fuels		(2,825	)		26,283			36,727
Natural gas and electricity		9,812			11,404			11,297
Services		(15,319	)		(24,369	)		(39,855	)
All other		(725	)		(1,966	)		(5,321	)
Corporate		(60,361	)		(54,025	)		(57,955	)

Total income before interest expense and provision for income taxes		150,128			164,596			129,738

Reconciliation to income from continuing operations
Interest expense, net		37,052			35,596			40,680
Provision for income taxes		1,903			5,653			764

Income from continuing operations	$	111,173		$	123,347		$	88,294


Depreciation and amortization:
Propane	$	15,515		$	16,229		$	20,380
Fuel oil and refined fuels		3,381			3,493			4,351
Natural gas and electricity		1,008			929			849
Services		312			344			710
All other		79			377			1,160
Corporate		8,099			7,418			5,203

Total depreciation and amortization	$	28,394		$	28,790		$	32,653


	As of
	September 27,			September 29,
	2008			2007
Assets:
Propane	$	746,281		$	747,391
Fuel oil and refined fuels		70,548			72,664
Natural gas and electricity		23,658			22,213
Services		2,841			1,985
All other		1,234			1,511
Corporate		279,132			231,098
Eliminations		(87,981	)		(87,981	)

Total assets	$	1,035,713		$	988,881

F-32


	Page
PART I

ITEM 1. BUSINESS		1

ITEM 1A. RISK FACTORS		11

ITEM 1B. UNRESOLVED STAFF COMMENTS		19

ITEM 2. PROPERTIES		20

ITEM 3. LEGAL PROCEEDINGS		20

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS		20

PART II

ITEM 5. MARKET FOR THE REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF UNITS		21

ITEM 6. SELECTED FINANCIAL DATA		22

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		26

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		48

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA		51

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE		54

ITEM 9A. CONTROLS AND PROCEDURES		54

ITEM 9B. OTHER INFORMATION		55

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND PARTNERSHIP GOVERNANCE		56

ITEM 11. EXECUTIVE COMPENSATION		61

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS		88

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE		90

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES		91

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES		92

SIGNATURES		93

Exhibit 10.1
Exhibit 10.5
Exhibit 21.1
Exhibit 23.1
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

	1.		Financial Statements

			See “Index to Financial Statements” set forth on page F-1.

	2.		Financial Statement Schedule

			See “Index to Financial Statement Schedule” set forth on page S-1.

	3.		Exhibits

			See “Index to Exhibits” set forth on page E-1.


	Page

Report of Independent Registered Public Accounting Firm		F-2

Consolidated Balance Sheets — As of September 27, 2008 and September 29, 2007		F-3

Consolidated Statements of Operations — Years Ended September 27, 2008, September 29, 2007 and September 30, 2006		F-4

Consolidated Statements of Cash Flows — Years Ended September 27, 2008, September 29, 2007 and September 30, 2006		F-5

Consolidated Statements of Partners’ Capital — Years Ended September 27, 2008, September 29, 2007 and September 30, 2006		F-6

Notes to Consolidated Financial Statements		F-7


	Page
Schedule II Valuation and Qualifying Accounts — Years Ended September 27, 2008, September 29, 2007 and September 30, 2006		S-2


	Balance at		Charged							Balance
	Beginning		to Costs and		Other					at End
	of Period		Expenses		Additions		Deductions (a)			of Period

Year Ended September 30, 2006

Allowance for doubtful accounts	$	9,965	$	2,463	$	—	$	(6,898	)	$	5,530
Valuation allowance for deferred tax assets		51,498		—		—		(3,765	)		47,733

Year Ended September 29, 2007

Allowance for doubtful accounts	$	5,530	$	4,331	$	—	$	(4,820	)	$	5,041
Valuation allowance for deferred tax assets		47,733		—		—		(4,437	)		43,296

Year Ended September 27, 2008

Allowance for doubtful accounts	$	5,041	$	9,166	$	—	$	(7,629	)	$	6,578
Valuation allowance for deferred tax assets		43,296		6,930		—		(1,331	)		48,895