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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 24, 2011


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 (State or other jurisdiction of incorporation or organization)		22-3410353 (I.R.S. Employer 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* Common Units		*Name of each exchange on which registered* 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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes 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 25, 2011 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 ($55.73 per unit), was approximately $1,972,717,000.


Documents Incorporated by Reference: None		Total number of pages (excluding Exhibits): 123

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 or acquire new customers;

•

The impact of customer conservation, energy efficiency and technology advances on the demand for propane, fuel oil and other refined fuels, natural gas and electricity;

•

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, derivative instruments and other regulatory developments on the Partnership’s business;

•

The impact of changes in tax regulations that could adversely affect the tax treatment of the Partnership for federal income tax purposes;

•

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;

•

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

•

Other risks referenced from time to time in filings with the Securities and Exchange Commission (“SEC”) and those factors listed or incorporated by reference into this Annual Report under “Risk Factors.”

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 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 2011, that we are the fifth largest retail marketer of propane in the United States, measured by retail gallons sold in the calendar year 2010. As of September 24, 2011, we were serving the energy needs of approximately 750,000 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 298.9 million gallons of propane and 37.2 million gallons of fuel oil and refined fuels to retail customers during the year ended September 24, 2011. 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 whose sole member is the Chief Executive Officer of the Partnership. Since October 19, 2006, the General Partner has had no economic interest in either the Partnership or the Operating Partnership (which means that the General Partner is not entitled to any cash distributions of either partnership, nor to any cash payment upon the liquidation of either partnership, nor any other economic rights in either partnership) other than as a holder of 784 Common Units of the Partnership. Additionally, under the Third Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”) of the Partnership, there are no incentive distribution rights for the benefit of the General Partner. The Partnership owns (directly and indirectly) all of the limited partner interests in the Operating Partnership. 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 two retail stores in the northwest and northeast regions as of September 24, 2011. Suburban Franchising creates and develops propane related franchising business opportunities.

Through an acquisition in fiscal 2004, 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 either limited liability company or corporate entities (collectively referred to as “Corporate Entities”) and, as such, are subject to corporate level income tax.

Suburban Energy Finance Corporation, a direct 100%-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 senior notes. 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. 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 an information request 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 24, 2011, 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 steady or 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. We have developed a streamlined operating footprint and management structure to facilitate effective resource planning and decision making. Our internal efforts are particularly focused in the areas of route optimization, forecasting customer usage, inventory control, cash management and customer tracking.

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 highly responsive 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. During fiscal 2011, we completed an acquisition of a mid-sized propane business in a market where we already have a strong presence. During fiscal 2010 we completed four acquisitions of mid-sized propane businesses; there were no acquisitions completed during fiscal 2009. These acquisitions complemented our existing operations, expanded our customer base and, with our focus on operational efficiencies, provided synergies through the blending of operations and assets into our existing facilities.

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 maximize the growth and profit potential of all of our assets.

Business Segments

We manage and evaluate our operations in five operating segments, three of which are reportable segments: Propane, Fuel Oil and Refined Fuels and Natural Gas and Electricity. 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 24, 2011. Our operations are concentrated in the east and west coast regions of the United States, including Alaska. As of September 24, 2011, we serviced approximately 608,000 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. These deliveries are scheduled through computer technology, based upon each customer’s historical consumption patterns and prevailing weather conditions. Additionally, 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 91% of the propane gallons sold by us in fiscal 2011 were to retail customers: 45% to residential customers, 28% to commercial customers, 8% to industrial customers, 4% to agricultural customers and 15% to other retail users. The balance of approximately 9% of the propane gallons sold by us in fiscal 2011 was for risk management activities and wholesale customers. No single customer accounted for 10% or more of our propane revenues during fiscal 2011.

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.

Supply

Our propane supply is purchased from approximately 61 oil companies and natural gas processors at approximately 110 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 2012. During fiscal 2011, Targa Liquids Marketing and Trade (“Targa”) and Enterprise Products Operating L.P. (“Enterprise”) provided approximately 17% and 11% of our total propane purchases, respectively. 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 or Enterprise 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, our margins could be affected. Approximately 96% of our total propane purchases were from domestic suppliers in fiscal 2011.

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 forward and option contracts with various third parties to purchase and sell propane 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. 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 24, 2011, the majority of our storage capacity in California was leased to third parties.

Competition

According to the Energy Information Administration’s Short-Term Energy Outlook Model Documentation (November 2009), propane ranks as the fourth most important source of residential energy in the nation, with about 5% of all households using propane as their primary space heating fuel. 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 (“BTU”) basis in locations serviced by natural gas, but it is an alternative or supplement 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 may arise as new neighborhoods are developed in geographically remote areas. Over the last year or so, fewer new housing developments have been started in our service areas as a result of recent economic circumstances.

Propane has some relative advantages over other energy sources. For example, in certain geographic areas, propane is generally less expensive to use than electricity for space heating, water heating, clothes drying and cooking. Utilization of fuel oil is geographically limited (primarily in the northeast), and even in that region, 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 2009 Sales of Natural Gas Liquids and Liquefied Refinery Gases, as published by the American Petroleum Institute in December 2010, and LP/Gas Magazine dated February 2011, the ten largest retailers, including us, account for approximately 39% of the total retail sales of propane in the United States. For fiscal years 2009 through 2011, no single marketer had a greater than 10% share of the total retail propane market in the United States. 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 areas the marketing radius may be extended by one or more satellite offices. Most of our customer service centers compete with five or more marketers or distributors.

Fuel Oil and Refined Fuels

Product Distribution and Marketing

We market and distribute fuel oil, kerosene, diesel fuel and gasoline to approximately 48,000 residential and commercial customers in the northeast region of the United States. Sales of fuel oil and refined fuels for fiscal 2011 amounted to 37.2 million gallons. Approximately 71% of the fuel oil and refined fuels gallons sold by us in fiscal 2011 were to residential customers, principally for home heating, 4% were to commercial customers, 1% were to agricultural and 5% to other users. Sales of diesel and gasoline accounted for the remaining 19% of total volumes sold in this segment during fiscal 2011. Fuel oil has a more limited use, compared to propane, and is used almost exclusively 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 operate motor vehicles.

Approximately 46% of our fuel oil customers receive their fuel oil under an automatic delivery system. These deliveries are scheduled through computer technology, based upon each customer’s historical consumption patterns and prevailing weather conditions. Additionally, we offer our customers a budget payment plan whereby the customer’s estimated annual fuel oil purchases 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 2011.

Supply

We obtain fuel oil and other refined fuels in pipeline, truckload or tankwagon quantities, and have contracts with certain pipeline and terminal operators for the right to temporarily store fuel oil at 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 2012.

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 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 100%-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 87,000 natural gas and electricity customers in New York and Pennsylvania. During fiscal 2011, we sold approximately 4.1 million dekatherms of natural gas and 613.9 million kilowatt hours of electricity through the natural gas and electricity segment. Approximately 75% of our customers were residential households and the remainder were 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 is 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.

All Other

We sell, install and service various types of whole-house heating products, air cleaners, humidifiers, hearth products and space heaters to the customers of our propane, fuel oil, natural gas and electricity businesses. 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. 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.

In addition, activities from our HomeTown Hearth & Grill and Suburban Franchising subsidiaries are also included in the all other business category.

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 on propane, fuel oil or natural gas primarily 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,” “Suburban Cylinder Express” and “HomeTown Hearth & Grill.” Additionally, we hold 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 products. 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 some constituents contained in fuel oil are considered hazardous substances. 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.

Through an acquisition in fiscal 2004, we acquired certain 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 24, 2011, we had accrued environmental liabilities of $0.6 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.

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. We have 474 facilities registered with the DHS, of which 454 facilities have been determined to be “Not a High Risk Chemical Facility”. 20 facilities have been determined by DHS to be High Risk, Tier 4 (lowest level of security risk). Security Vulnerability Assessments for the 20 facilities have been submitted to the DHS and the DHS has reviewed 17 of them, requiring us to submit Site Security Plans for those facilities. Pending DHS review, the remaining 3 facilities may require Site Security Plans within 90 days of DHS notification. 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.

In December 2009, the U.S. Environmental Protection Agency (“EPA”) issued an “Endangerment Finding” under the Clean Air Act, determining that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment because emissions of such gases may be contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs and require reporting by certain regulated facilities on an annual basis.

Both Houses of the United States Congress also have considered adopting legislation to reduce emissions of GHGs. In June 2009, the American Clean Energy and Security Act of 2009, also known as the Waxman-Markey Bill, passed in the U.S. House of Representatives, but the U.S. Senate’s version, The Clean Energy Jobs and American Power Act, or the Boxer-Kerry Bill, did not pass. Both bills sought to establish a “cap and trade” system for restricting GHG emissions. Under such system, certain sources of GHG emissions would be required to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. The number of emission allowances issued each year would decline as necessary to meet overall emission reduction goals. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly.

The adoption of federal or state climate change legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased capital and operating costs, with resulting impact on product price and demand. We cannot predict whether or in what form cap-and-trade provisions and renewable energy standards may be enacted. In addition, a possible consequence of climate change is increased volatility in seasonal temperatures. It is difficult to predict how the market for our fuels would be affected by increased temperature volatility, although if there is an overall trend of warmer temperatures, it could adversely affect our business.

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.

On July 21, 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) was signed into law. The Dodd-Frank Act regulates derivative transactions, which include certain instruments used by the Partnership for risk management activities.

The Dodd-Frank Act requires the Commodity Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations relating to, among other things, swaps, participants in the derivatives markets, clearing of swaps and reporting of swap transactions. In general, the Dodd-Frank Act subjects swap transactions and participants to greater regulation and supervision by the CFTC and the SEC and will require many swaps to be cleared through a registered CFTC- or SEC-clearing facility and executed on a designated exchange or swap execution facility. There are some exceptions to these requirements for entities that use swaps to hedge or mitigate commercial risk. While we may ultimately be eligible for such exceptions, the scope of these exceptions currently is somewhat uncertain, pending further definition through rulemaking.

Among the other provisions of the Dodd-Frank Act that may affect derivative transactions are those relating to establishment of capital and margin requirements for certain derivative participants; establishment of business conduct standards, recordkeeping and reporting requirements; and imposition of position limits.

Although the Dodd-Frank Act imposes significant new regulatory requirements with respect to derivatives, the impact of the requirements will not be known definitively until final regulations have been adopted by the CFTC and the SEC. The new legislation and regulations promulgated thereunder could increase the operational and transactional cost of derivatives contracts and affect the number and/or creditworthiness of counterparties available to us.

Employees

As of September 24, 2011, we had 2,385 full time employees, of whom 477 were engaged in general and administrative activities (including fleet maintenance), 37 were engaged in transportation and product supply activities and 1,871 were customer service center employees. As of September 24, 2011, 44 of our employees were represented by 5 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 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 on propane, fuel oil or natural gas primarily 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 1%, 5% and 1% warmer than normal for fiscal 2011, fiscal 2010 and fiscal 2009, respectively, as measured by the number of heating degree days reported by the National Oceanic and Atmospheric Administration. 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 propane 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. 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.

High prices for propane, fuel oil and other refined fuels and natural gas can lead to customer conservation, resulting in reduced demand for our product.

Prices for propane, fuel oil and other refined fuels and natural gas are subject to fluctuations in response to changes in wholesale prices and other market conditions beyond our control. Therefore, our average retail sales prices can vary significantly within a heating season or from year to year as wholesale prices fluctuate with propane, fuel oil and natural gas commodity market conditions. During periods of high propane, fuel oil and other refined fuels and natural gas product costs our selling prices generally increase. High prices can lead to customer conservation, resulting in reduced demand for our product.

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 and fuel oil to be relatively flat to moderately declining over the next several years. 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 and the impact of continued weakness in the economy on customer buying habits.

Propane and fuel oil compete 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 on an equivalent BTU basis. 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. We expect this trend to continue. 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 of those respective products principally on the basis of price, service and availability. 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. In addition, our existing fuel oil customers, unlike our existing propane customers, generally own their own tanks, which can result in intensified competition for these customers.

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 can give no assurance that we will be able to acquire other retail distributors, add new customers and retain existing customers.

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, continued weakness in the economy may lead to additional conservation by retail customers seeking to further reduce their heating costs, particularly during periods of sustained higher commodity prices. Future technological advances in heating, conservation and energy generation and continued economic weakness may adversely affect our volumes sold, which, in turn, 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, political unrest and the current hostilities in the Middle East or other energy producing regions may adversely affect the economy and the price and availability of propane, fuel oil and other refined fuels and natural gas.

Terrorist attacks, political unrest and the current hostilities in the Middle East or other energy producing regions 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, political unrest and hostilities in the Middle East or other energy producing regions 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 and ever increasing 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. 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, both as a result of these operating hazards and risks and as a result of other aspects of our 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, or 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 expect overall demand for propane and fuel oil to be relatively flat to moderately declining over the next several years. With respect to our retail propane business, it may be difficult for us to increase our aggregate number of 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.

The adoption of climate change legislation could result in increased operating costs and reduced demand for the products and services we provide.

In December 2009, the EPA issued an “Endangerment Finding” under the Clean Air Act, determining that emissions of GHGs present an endangerment to public health and the environment because emissions of such gases may be contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs and require reporting by certain regulated facilities on an annual basis.

The adoption of derivatives legislation by Congress could have an adverse impact on our ability to hedge risks associated with our business.

On July 21, 2010, the Dodd-Frank Act was signed into law. The Dodd-Frank Act regulates derivative transactions, which include certain instruments used in our risk management activities.

The Dodd-Frank Act requires the CFTC and the SEC to promulgate rules and regulations relating to, among other things, swaps, participants in the derivatives markets, clearing of swaps and reporting of swap transactions. In general, the Dodd-Frank Act subjects swap transactions and participants to greater regulation and supervision by the CFTC and the SEC and will require many swaps to be cleared through a CFTC- or SEC-registered clearing facility and executed on a designated exchange or swap execution facility. There are some exceptions to these requirements for entities that use swaps to hedge or mitigate commercial risk. While we may ultimately be eligible for such exceptions, the scope of these exceptions currently is somewhat uncertain, pending further definition through rulemaking.

Although the Dodd-Frank Act imposes significant new regulatory requirements with respect to derivatives, the impact of the requirements will not be known definitively until new regulations have been adopted by the CFTC and the SEC. The new legislation and regulations promulgated thereunder could increase the operational and transactional cost of derivatives contracts and affect the number and/or creditworthiness of counterparties available to us.

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:

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

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

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issuances of debt and equity securities;

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our ability to control expenses;

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fluctuations in working capital;

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capital expenditures; and

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financial, business and other factors, a number 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 24, 2011, we had total outstanding borrowings of $350.0 million, consisting of $250.0 million of senior notes issued by the Partnership and our 100%-owned subsidiary, Suburban Energy Finance Corporation, and $100.0 million of borrowings outstanding under the Operating Partnership’s revolving credit facility. 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 may make 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 revolving credit facility and the senior notes both contain various restrictive and affirmative covenants applicable to us and the Operating 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. The revolving credit facility contains certain financial covenants: (a) requiring our consolidated interest coverage ratio, as defined, to be not less than 2.5 to 1.0 as of the end of any fiscal quarter; (b) prohibiting our total consolidated leverage ratio, as defined, from being greater than 4.5 to 1.0 as of the end of any fiscal quarter; and (c) prohibiting the senior secured consolidated leverage ratio, as defined, of the Operating Partnership from being greater than 3.0 to 1.0 as of the end of any fiscal quarter. Under the 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. We and the Operating Partnership were in compliance with all covenants and terms of the senior notes and the revolving credit facility as of September 24, 2011.

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 and the right to vote on the removal of the general partner.

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 acquirer from conducting a solicitation of proxies to elect the acquirer’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:

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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

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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 Unitholders that existed prior to the new issuance.

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. One of the requirements for such classification is that at least 90% of our gross income for each taxable year has been and will be “qualifying income” within the meaning of Section 7704 of the Internal Revenue Code. Whether we will continue to be classified as a partnership in part depends on our ability to meet this qualifying income test in the future. 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. Members of Congress have proposed substantive changes to the current federal income tax laws that would affect certain publicly traded partnerships and legislation that would eliminate partnership tax treatment for certain publicly traded partnerships. 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. Any modification to the U.S. tax laws and interpretations thereof may or may not be applied retroactively. 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.

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 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.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our Common Units each month based upon the ownership of our Common Units on the first day of each month, instead of on the basis of the date a particular Common Unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our Unitholders.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our Common Units each month based upon the ownership of our Common Units on the first day of each month, instead of on the basis of the date a particular Common Unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. If the IRS were to challenge this method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our Unitholders.

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.

There are state, local and other tax considerations for our Unitholders.

In addition to United States federal income taxes, Unitholders will likely be subject to other taxes, such as state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, even if the Unitholder does not reside in any of those jurisdictions. A Unitholder will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of the various jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. It is the responsibility of each Unitholder to file all United States federal, state and local income tax returns that may be required of such Unitholder.


ITEM 1B.		UNRESOLVED STAFF COMMENTS

None.


ITEM 2.		PROPERTIES

As of September 24 2011, we owned approximately 66% 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. 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 24 2011, we had a fleet of 6 transport truck tractors, of which we owned two, and 23 railroad tank cars, of which we owned none. In addition, as of September 24, 2011 we had 668 bobtail and rack trucks, of which we owned 33%, 88 fuel oil tankwagons, of which we owned 25%, and 866 other delivery and service vehicles, of which we owned 41%. We lease the vehicles we do not own. As of September 24, 2011, we also owned 655,003 customer propane storage tanks with typical capacities of 100 to 500 gallons, 139,813 customer propane storage tanks with typical capacities of over 500 gallons and 217,842 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. We have been, and will continue to be, a defendant in various legal proceedings and litigation arising in the ordinary course of business, both as a result of these operating hazards and risks, and as a result of other aspects of our business. In this regard, we currently are a defendant in putative suits in several states. The complaints allege a number of claims, including as to our pricing, fee disclosure and tank ownership, under various consumer statutes, the Uniform Commercial Code, common law and antitrust law. Based on the nature of the allegations under these suits, we believe that the suits are without merit and we are contesting each of these suits vigorously. 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 $52.8 million at September 24, 2011), 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 future results of operations, financial condition or cash flow, after considering our self-insurance reserves for known and unasserted claims, as well as existing insurance policies in force. 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 $17.5 million at September 24, 2011). With respect to the pending putative suits, other than for legal defense fees and expenses, based on the merits of the allegations, a liability for a loss contingency is not required at this time.


ITEM 4.		REMOVED AND RESERVED

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 21, 2011, there were 700 Unitholders of record (based on the number of record holders and nominees for those Common Units held in street name). 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 2011
First Quarter	$	57.24	$	51.50	$	0.8525
Second Quarter		58.99		49.30		0.8525
Third Quarter		57.89		49.90		0.8525
Fourth Quarter		53.23		40.25		0.8525

Fiscal 2010
First Quarter	$	47.12	$	41.10	$	0.8350
Second Quarter		50.00		42.53		0.8400
Third Quarter		49.46		39.16		0.8450
Fourth Quarter		55.01		45.85		0.8500

We make quarterly distributions to our partners in an aggregate amount equal to our Available Cash (as defined in our Partnership Agreement) 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			September			September			September			September
	24, 2011			25, 2010			26, 2009			27, 2008			29, 2007
Statement of Operations Data
Revenues	$	1,190,552		$	1,136,694		$	1,143,154		$	1,574,163		$	1,439,563
Costs and expenses		1,045,324			980,508			932,539			1,424,035			1,270,213
Severance charges (a)		2,000			—			—			—			1,485
Pension settlement charge (b)		—			2,818			—			—			3,269
Operating income		143,228			153,368			210,615			150,128			164,596
Interest expense, net		27,378			27,397			38,267			37,052			35,596
Loss on debt extinguishment (c)		—			9,473			4,624			—			—
Provision for income taxes		884			1,182			2,486			1,903			5,653
Income from continuing operations		114,966			115,316			165,238			111,173			123,347
Discontinued operations:
Gain on disposal of discontinued operations (d)		—			—			—			43,707			1,887
Income from discontinued operations		—			—			—			—			2,053
Net income		114,966			115,316			165,238			154,880			127,287
Income from continuing operations per Common Unit — basic		3.24			3.26			4.99			3.39			3.79
Net income per Common Unit — basic (e)		3.24			3.26			4.99			4.72			3.91
Net income per Common Unit — diluted (e)		3.22			3.24			4.96			4.70			3.89
Cash distributions declared per unit	$	3.41		$	3.35		$	3.26		$	3.09		$	2.76

Balance Sheet Data (f)
Cash and cash equivalents	$	149,553		$	156,908		$	163,173		$	137,698		$	96,586
Current assets		297,822			296,427			307,556			359,551			295,940
Total assets		956,459			970,914			978,168			1,036,367			988,947
Current liabilities, excluding short-term borrowings and current portion of long-term borrowings		151,514			164,514			181,930			226,780			206,633
Total debt		348,169			347,953			349,415			531,772			548,538
Total liabilities		598,241			608,258			620,632			818,472			822,670
Partners’ capital — Common Unitholders	$	418,134		$	419,882		$	418,824		$	262,050		$	208,230

Statement of Cash Flows Data
Cash provided by (used in)
Operating activities	$	132,786		$	155,797		$	246,551		$	120,517		$	145,957
Investing activities		(19,505	)		(30,111	)		(16,852	)		36,630			(19,689	)
Financing activities	$	(120,636	)	$	(131,951	)	$	(204,224	)	$	(116,035	)	$	(90,253	)

Other Data
Depreciation and amortization — continuing operations	$	35,628		$	30,834		$	30,343		$	28,394		$	28,790
Depreciation and amortization — discontinued operations		—			—			—			—			452
EBITDA (g)		178,856			174,729			236,334			222,229			197,778
Adjusted EBITDA (g)		179,425			192,420			239,245			220,465			210,087
Capital expenditures — maintenance and growth (h)	$	22,284		$	19,131		$	21,837		$	21,819		$	26,756
Retail gallons sold
Propane		298,902			317,906			343,894			386,222			432,526
Fuel oil and refined fuels		37,241			43,196			57,381			76,515			104,506


(a)		During fiscal 2011, we recorded severance charges of $2.0 million related to the realignment of our regional operating footprint in response to the persistent and foreseeable challenges affecting the industry as a whole. During fiscal 2007, we incurred $1.5 million in charges associated with severance for positions eliminated unrelated to any specific plan of restructuring.


(b)		We incurred non-cash pension settlement charges of $2.8 million and $3.3 million during fiscal 2010 and 2007, respectively, 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.

(c)		During fiscal 2010 we completed the issuance of $250.0 million of 7.375% senior notes maturing in March 2020 to replace the previously existing 6.875% senior notes that were set to mature in December 2013. In connection with the refinancing, we recognized a loss on debt extinguishment of $9.5 million in the second quarter of fiscal 2010, consisting of $7.2 million for the repurchase premium and related fees, as well as the write-off of $2.2 million in unamortized debt origination costs and unamortized discount. During fiscal 2009, we purchased $175.0 million aggregate principal amount of the 6.875% senior notes through a cash tender offer. In connection with the tender offer, we recognized a loss on the extinguishment of debt of $4.6 million in the fourth quarter of fiscal 2009, consisting of $2.8 million for the tender premium and related fees, as well as the write-off of $1.8 million in unamortized debt origination costs and unamortized discount.

(d)		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”). 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. The gains on disposal have been accounted for within discontinued operations. The prior period results of operations attributable to the sale of our Tirzah, South Carolina storage cavern and associated pipeline have been reclassified to remove their financial results from continuing operations.

(e)		Computations of basic earnings per Common Unit were performed by dividing net income by the weighted average number of outstanding Common Units, and restricted units granted under our restricted unit plans to retirement-eligible grantees. Computations of diluted earnings per Common Unit were performed by dividing net income by the weighted average number of outstanding Common Units and unvested restricted units granted under our restricted unit plans.

(f)		Other assets and other liabilities on the consolidated balance sheet were increased $654 and $2,835, respectively, with a corresponding decrease of $2,181 to common unitholders as of September 27, 2008 to record an asset and a liability that were not captured in prior years.

(g)		EBITDA represents net income before deducting interest expense, income taxes, depreciation and amortization. Adjusted EBITDA represents EBITDA excluding the unrealized net gain or loss from mark-to-market activity for derivative instruments, loss on debt extinguishment, pension settlement charge and severance charges. Our management uses EBITDA and Adjusted EBITDA as measures of liquidity and we are including them because we believe that they provide 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 Adjusted EBITDA as the performance target. Moreover, our revolving credit agreement requires us to use Adjusted EBITDA in calculating our leverage and interest coverage ratios. EBITDA and Adjusted EBITDA are not recognized terms under accounting principles generally accepted in the United States of America (“US GAAP”) and should not be considered as an alternative to net income or net cash provided by operating activities determined in accordance with US GAAP. Because EBITDA and Adjusted EBITDA as determined by us excludes some, but not all, items that affect net income, they may not be comparable to EBITDA and Adjusted 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
	2011			2010			2009			2008			2007
Net income	$	114,966		$	115,316		$	165,238		$	154,880		$	127,287
Add:
Provision for income taxes		884			1,182			2,486			1,903			5,653
Interest expense, net		27,378			27,397			38,267			37,052			35,596
Depreciation and amortization
Continuing operations		35,628			30,834			30,343			28,394			28,790
Discontinued operations		—			—			—			—			452

EBITDA		178,856			174,729			236,334			222,229			197,778
Unrealized (non-cash) (gains) losses on changes in fair value of derivatives		(1,431	)		5,400			(1,713	)		(1,764	)		7,555
Severance charges		2,000			—			—			—			1,485
Loss on debt extinguishment		—			9,473			4,624			—			—
Pension settlement charge		—			2,818			—			—			3,269

Adjusted EBITDA		179,425			192,420			239,245			220,465			210,087
Add (subtract):
Provision for income taxes — current		(884	)		(1,182	)		(1,101	)		(626	)		(1,853	)
Interest expense, net		(27,378	)		(27,397	)		(38,267	)		(37,052	)		(35,596	)
Unrealized (non-cash) gains (losses) on changes in fair value of derivatives		1,431			(5,400	)		1,713			1,764			(7,555	)
Severance charges		(2,000	)		—			—			—			(1,485	)
Compensation cost recognized under Restricted Unit Plan		3,922			4,005			2,396			2,156			3,014
(Gain) loss on disposal of property, plant and equipment, net		(2,772	)		38			(650	)		(2,252	)		(2,782	)
Gain on disposal of discontinued operations		—			—			—			(43,707	)		(1,887	)
Changes in working capital and other assets and liabilities		(18,958	)		(6,687	)		43,215			(20,231	)		(15,986	)


Net cash provided by operating activities	$	132,786		$	155,797		$	246,551		$	120,517		$	145,957


(h)		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.


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 supply and demand dynamics 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 also purchase product on the open market. We attempt to reduce price risk by pricing product on a short-term basis. 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.

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, periods of sustained higher commodity prices can lead to customer conservation, resulting in reduced demand for our product.

Seasonality

The retail propane and fuel oil distribution businesses, as well as the natural gas marketing business, are seasonal because these fuels are primarily used 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 fourth quarter and following fiscal year first quarter.

Weather

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.

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 futures and option contracts traded on the New York Mercantile Exchange (“NYMEX”) to purchase and sell propane, fuel oil and crude 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 whereas futures and option contracts 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 Audit Committee, through enforcement of our Hedging and Risk Management Policy.

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 accounting principles generally accepted in the United States of America (“US 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 approximately 750,000 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 or decrease of 100 basis points in the discount rate would have an immaterial impact on net pension and postretirement benefit costs.

Self-Insurance Reserves. Our accrued self-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 unasserted 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.

Loss Contingencies. In the normal course of business, we are involved in various claims and legal proceedings. We record a liability for such matters when it is probable that a loss has been incurred and the amounts can be reasonably estimated. The liability includes probable and estimable legal costs to the point in the legal matter where we believe a conclusion to the matter will be reached. When only a range of possible loss can be established, the most probable amount in the range is accrued. If no amount within this range is a better estimate than any other amount within the range, the minimum amount in the range is accrued.

Results of Operations and Financial Condition

Net income for fiscal 2011 amounted to $115.0 million, or $3.24 per Common Unit, compared to $115.3 million, or $3.26 per Common Unit, in fiscal 2010. Earnings before interest, taxes, depreciation and amortization (“EBITDA”) for fiscal 2011 amounted to $178.9 million, compared to $174.7 million for fiscal 2010.

Net income and EBITDA for fiscal 2011 included a $2.0 million charge for severance costs associated with the realignment of the Partnership’s field operations, as well as a non-cash charge of $2.9 million to accelerate depreciation expense on assets taken out of service. By comparison, net income and EBITDA for fiscal 2010 included: (i) a loss on debt extinguishment of $9.5 million associated with a refinancing of the Partnership’s senior notes; (ii) a non-cash pension settlement charge of $2.8 million; and (iii) a non-cash charge of $1.8 million to accelerate depreciation expense on assets taken out of service. Adjusted EBITDA (as defined and reconciled below) amounted to $179.4 million in fiscal 2011, compared to $192.4 million in fiscal 2010.

Retail propane gallons sold for fiscal 2011 decreased 19.0 million gallons, or 6.0%, to 298.9 million gallons from 317.9 million gallons in fiscal 2010. Sales of fuel oil and other refined fuels for fiscal 2011 decreased 6.0 million gallons, or 13.9%, to 37.2 million gallons compared to 43.2 million gallons in the prior year. Sales volumes in both segments continued to be negatively affected by weakness in the economy, coupled with customer conservation attributable to the high commodity price environment relative to historical levels. Average posted prices for propane and fuel oil were 26.7% and 36.6% higher, respectively, compared to fiscal 2010, as commodity prices continued to rise throughout much of fiscal 2011. From a weather perspective, average temperatures for fiscal 2011 were 1% warmer than normal, compared to 5% warmer than normal in the prior year.

Revenues for fiscal year 2011 of $1,190.6 million increased $53.9 million, or 4.7%, compared to the prior year, primarily due to higher average selling prices attributable to higher base commodity prices, offset to an extent by lower volumes sold. Cost of products sold for fiscal 2011 of $678.7 million increased $80.2 million, or 13.4%, compared to $598.5 million in the prior year as a result of higher wholesale product costs. Cost of products sold in fiscal 2011 included a $1.4 million unrealized (non-cash) gain attributable to the mark-to-market adjustment for derivative instruments used in risk management activities, compared to a $5.4 million unrealized (non-cash) loss in the prior year; these unrealized gains and losses are excluded from Adjusted EBITDA for both periods.

Combined operating and general and administrative expenses of $331.0 million for fiscal year 2011 were $20.2 million, or 5.8%, lower than the prior year, primarily due to lower variable compensation attributed to lower earnings and continued savings in payroll and benefit related expenses, offset to an extent by higher fuel costs to operate our fleet. Depreciation and amortization expense of $35.6 million increased $4.8 million, or 15.6%, primarily due to the impact of prior year acquisitions, as well as from the increase in accelerated depreciation for assets taken out of service referenced above.

Net interest expense of $27.4 million for fiscal 2011 was flat with the prior year. For the fifth consecutive year, the Partnership funded all working capital requirements with cash on hand without the need to borrow under its working capital facility and ended the year with $149.6 million of cash.

As we look ahead to fiscal 2012, our anticipated cash requirements include: (i) maintenance and growth capital expenditures of approximately $22.0 million; (ii) approximately $26.2 million of interest and income tax payments; and (iii) assuming distributions remain at the current annualized level of $3.41 per Common Unit, approximately $121.2 million of distributions to Unitholders. Based on our current cash position, availability under the Revolving Credit Agreement (unused borrowing capacity of $95.1 million at September 24, 2011) 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 2012, we currently do not expect to borrow under our credit facility to fund those requirements.

Fiscal Year 2011 Compared to Fiscal Year 2010

Revenues


								Percent
	Fiscal		Fiscal		Increase/			Increase/
(Dollars in thousands)	2011		2010		(Decrease)			(Decrease)
Revenues
Propane	$	929,492	$	885,459	$	44,033			5.0	%
Fuel oil and refined fuels		139,572		135,059		4,513			3.3	%
Natural gas and electricity		84,721		77,587		7,134			9.2	%
All other		36,767		38,589		(1,822	)		(4.7	%)

Total revenues	$	1,190,552	$	1,136,694	$	53,858			4.7	%

Total revenues increased $53.9 million, or 4.7%, to $1,190.6 million in fiscal 2011 compared to $1,136.7 million for fiscal 2010, due to higher average selling prices associated with higher product costs, partially offset by lower volumes sold. From a weather perspective, average temperatures as measured in heating degree days, as reported by the National Oceanic and Atmospheric Administration (“NOAA”), in our service territories during fiscal 2011 were 1% warmer than normal and 4% colder than the prior year.

Revenues from the distribution of propane and related activities of $929.5 million for fiscal 2011 increased $44.0 million, or 5.0%, compared to $885.5 million for fiscal 2010, primarily as a result of higher average selling prices associated with higher product costs, partially offset by lower volumes sold. Average propane selling prices in fiscal 2011 increased 8.9% compared to the prior year due to higher product costs, thereby having a positive impact on revenues. This increase was partially offset by lower retail propane gallons sold in fiscal 2011 which decreased 19.0 million gallons, or 6.0%, to 298.9 million gallons from 317.9 million gallons in the prior year. The volume decline was primarily due to customer conservation efforts attributable to the high commodity price environment and ongoing sluggish economic conditions. Additionally, included within the propane segment are revenues from other propane activities of $76.4 million in fiscal 2011, which increased $23.8 million compared to the prior year as a result of the settlement of certain contracts used for risk management purposes (see similar increase in cost of products sold).

Revenues from the distribution of fuel oil and refined fuels of $139.6 million for fiscal 2011 increased $4.5 million, or 3.3%, from $135.1 million in the prior year primarily as a result of higher average selling prices associated with higher product costs, partially offset by lower volumes sold. Average selling prices in our fuel oil and refined fuels segment in fiscal 2011 increased 20.1% compared to the prior year due to higher product costs, thereby having a positive impact on revenues. Fuel oil and refined fuels gallons sold in fiscal 2011 decreased 6.0 million gallons, or 13.8%, to 37.2 million gallons from 43.2 million gallons in the prior year. Lower volumes sold in our fuel oil and refined fuels segment were primarily attributable to our gasoline and diesel businesses and, to a lesser extent, our heating oil business.

Revenues in our natural gas and electricity segment increased $7.1 million, or 9.2%, to $84.7 million in fiscal 2011 compared to $77.6 million in the prior year as a result of higher natural gas and, to a lesser extent, electricity volumes sold, coupled with higher average selling prices associated with higher product costs.

Cost of Products Sold


										Percent
	Fiscal			Fiscal			Increase/			Increase/
(Dollars in thousands)	2011			2010			(Decrease)			(Decrease)
Cost of products sold
Propane	$	506,481		$	436,825		$	69,656			15.9	%
Fuel oil and refined fuels		100,908			92,037			8,871			9.6	%
Natural gas and electricity		61,495			57,892			3,603			6.2	%
All other		9,835			11,697			(1,862	)		(15.9	%)

Total cost of products sold	$	678,719		$	598,451		$	80,268			13.4	%


As a percent of total revenues		57.0	%		52.6	%

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, natural gas and electricity sold, 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 increased $80.3 million, or 13.4%, to $678.7 million in fiscal 2011 compared to $598.4 million in the prior year due to higher average product costs resulting from the increase in commodity prices, partially offset by lower volumes sold. Average posted prices for propane and fuel oil in fiscal 2011 were 26.7% and 36.6% higher, respectively, compared to the prior year. Cost of products sold in fiscal 2011 included a $1.4 million unrealized (non-cash) gain representing the net change in the fair value of derivative instruments during the period, compared to a $5.4 million unrealized (non-cash) loss in the prior year resulting in a decrease of $6.8 million in cost of products sold in fiscal 2011 compared to the prior year ($0.3 million decrease reported within the propane segment and $6.5 million decrease reported within the fuel oil and refined fuels segment).

Cost of products sold associated with the distribution of propane and related activities of $506.5 million for fiscal 2011 increased $69.7 million, or 15.9%, compared to the prior year. Higher average propane product costs resulted in an increase of $70.9 million in cost of products sold during fiscal 2011 compared to the prior year. The impact of the increase in average propane product costs was partially offset by lower propane volumes sold, which resulted in a $25.5 million decrease in cost of products sold during fiscal 2011 compared to the prior year. Cost of products sold from other propane activities increased $24.6 in fiscal 2011 compared to the prior year.

Cost of products sold associated with our fuel oil and refined fuels segment of $100.9 million for fiscal 2011 increased $8.9 million, or 9.6%, compared to the prior year. Higher average fuel oil and refined fuel product costs resulted in an increase of $27.3 million in cost of products sold during fiscal 2011 compared to the prior year. The impact of the increase in product costs was partially offset by lower fuel oil and refined fuels volumes sold, which resulted in an $11.9 million decrease in cost of products sold in fiscal 2011 compared to the prior year.

Cost of products sold in our natural gas and electricity segment of $61.5 million for fiscal 2011 increased $3.6 million, or 6.2%, compared to the prior year primarily due to higher natural gas and, to a lesser extent, electricity volumes sold, coupled with an increase in average product costs.

Cost of products sold as a percent of total revenues for fiscal 2011 increased 4.4 percentage points to 57.0% from 52.6% in the prior year. The increase in cost of products sold as a percentage of revenues was primarily attributable to wholesale product costs rising at a faster rate than average selling prices in fiscal 2011 compared to the prior year.

Operating Expenses


	Fiscal			Fiscal						Percent
(Dollars in thousands)	2011			2010			(Decrease)			(Decrease)
Operating expenses	$	279,329		$	289,567		$	(10,238	)		(3.5	%)
As a percent of total revenues		23.5	%		25.5	%

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 $279.3 million for fiscal 2011 decreased $10.2 million, or 3.5%, compared to $289.6 million in the prior year as a result of lower variable compensation associated with lower earnings, lower payroll and benefit related expenses resulting from operating efficiencies, and lower insurance costs. These savings were partially offset by an increase in fuel costs to operate our fleet.

General and Administrative Expenses


	Fiscal			Fiscal						Percent
(Dollars in thousands)	2011			2010			(Decrease)			(Decrease)
General and administrative expenses	$	51,648		$	61,656		$	(10,008	)		(16.2	%)
As a percent of total revenues		4.3	%		5.4	%

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 $51.6 million for fiscal 2011 decreased $10.0 million, or 16.2%, compared to $61.6 million in the prior year primarily as a result of lower variable compensation associated with lower earnings and the impact of a $2.5 million gain on sale of assets during the second quarter of fiscal 2011, partially offset by an increase in litigation costs for uninsured legal matters.

Depreciation and Amortization


	Fiscal			Fiscal					Percent
(Dollars in thousands)	2011			2010			Increase		Increase
Depreciation and amortization	$	35,628		$	30,834		$	4,794		15.5	%
As a percent of total revenues		3.0	%		2.7	%

Depreciation and amortization expense of $35.6 million in fiscal 2011 increased $4.8 million, or 15.5%, compared to $30.8 million in the prior year primarily as a result of tangible and intangible long-lived assets acquired in business combinations in fiscal 2011 and 2010, coupled with accelerated depreciation expense of $2.9 million and $1.8 million in fiscal 2011 and fiscal 2010, respectively, for assets taken out of service.

Interest Expense, net


	Fiscal			Fiscal						Percent
(Dollars in thousands)	2011			2010			(Decrease)			(Decrease)
Interest expense, net	$	27,378		$	27,397		$	(19	)		(0.1	%)
As a percent of total revenues		2.3	%		2.4	%

Net interest expense of $27.4 million in fiscal 2011 was flat compared to the prior year. See Liquidity and Capital Resources below for additional discussion on long-term borrowings.

Loss on Debt Extinguishment

On March 23, 2010, we repurchased $250.0 million aggregate principal amount of the 2013 Senior Notes through a cash tender offer. In connection with the repurchase, we recognized a loss on the extinguishment of debt of $9.5 million in the second quarter of fiscal 2010, consisting of $7.2 million for the repurchase premium and related fees, as well as the write-off of $2.3 million in unamortized debt origination costs and unamortized discount.

Net Income and Adjusted EBITDA

We reported net income of $115.0 million, or $3.24 per Common Unit in fiscal 2011 compared to net income of $115.3 million, or $3.26 per Common Unit in the prior year. Adjusted EBITDA amounted to $179.4 million in fiscal 2011, compared to $192.4 million in fiscal 2010.

Net income and EBITDA for fiscal 2011 were negatively impacted by a $2.0 million charge for severance costs associated with a realignment of our field operations, as well as a non-cash charge of $2.9 to accelerate depreciation expense on assets taken out of service. By comparison, net income and EBITDA for fiscal 2010 were negatively impacted by certain items, including: (i) a loss on debt extinguishment of $9.5 million associated with the refinancing of senior notes; (ii) a non-cash pension settlement charge of $2.8 million; and (iii) a non-cash charge of $1.8 million to accelerate depreciation expense on assets taken out of service.

Adjusted EBITDA represents EBITDA excluding the unrealized net gain or loss from mark-to-market activity for derivative instruments, loss on debt extinguishment, pension settlement charge and severance charges. Our management uses EBITDA and Adjusted EBITDA as measures of liquidity and we are including them because we believe that they provide 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 Adjusted EBITDA as the performance target. Moreover, our revolving credit agreement requires us to use Adjusted EBITDA as a component in calculating our leverage and interest coverage ratios. EBITDA and Adjusted EBITDA are not recognized terms under US GAAP and should not be considered as an alternative to net income or net cash provided by operating activities determined in accordance with US GAAP. Because EBITDA and Adjusted EBITDA as determined by us excludes some, but not all, items that affect net income, they may not be comparable to EBITDA and Adjusted 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:


	Year Ended
	September 24,			September 25,
(Dollars in thousands)	2011			2010

Net income	$	114,966		$	115,316
Add:
Provision for income taxes		884			1,182
Interest expense, net		27,378			27,397
Depreciation and amortization		35,628			30,834

EBITDA		178,856			174,729
Unrealized (non-cash) (gains) losses on changes in fair value of derivatives		(1,431	)		5,400
Severance charges		2,000			—
Loss on debt extinguishment		—			9,473
Pension settlement charge		—			2,818

Adjusted EBITDA		179,425			192,420
Add (subtract):
Provision for income taxes — current		(884	)		(1,182	)
Interest expense, net		(27,378	)		(27,397	)
Unrealized (non-cash) gains (losses) on changes in fair value of derivatives		1,431			(5,400	)
Severance charges		(2,000	)		—
Compensation cost recognized under Restricted Unit Plans		3,922			4,005
(Gain) loss on disposal of property, plant and equipment, net		(2,772	)		38
Changes in working capital and other assets and liabilities		(18,958	)		(6,687	)


Net cash provided by operating activities	$	132,786		$	155,797

Fiscal Year 2010 Compared to Fiscal Year 2009

Revenues


								Percent
	Fiscal		Fiscal		Increase/			Increase/
(Dollars in thousands)	2010		2009		(Decrease)			(Decrease)
Revenues
Propane	$	885,459	$	864,012	$	21,447			2.5	%
Fuel oil and refined fuels		135,059		159,596		(24,537	)		(15.4	)%
Natural gas and electricity		77,587		76,832		755			1.0	%
All other		38,589		42,714		(4,125	)		(9.7	)%

Total revenues	$	1,136,694	$	1,143,154	$	(6,460	)		(0.6	)%

Total revenues decreased $6.5 million, or 0.6%, to $1,136.7 million for the year ended September 25, 2010 compared to $1,143.2 million for the year ended September 26, 2009, due to lower volumes, partially offset by higher average selling prices associated with higher product costs. Volumes for the fiscal 2010 were lower than the prior year due to the negative impact of adverse economic conditions, particularly on our commercial and industrial accounts, as well as the unfavorable impact of warmer average temperatures, particularly in our northeastern and western service territories, and ongoing residential customer conservation. From a weather perspective, average temperatures as measured in heating degree days, as reported by NOAA, in our service territories during fiscal 2010 were 5% warmer than normal and 4% warmer than the prior year. In our northeastern territories, which is where we have a higher concentration of residential propane customers and all of our fuel oil customers, average temperatures during fiscal 2010 were 9% warmer than both normal and the prior year. The unfavorable weather pattern occurred primarily during the peak heating months (from October through March) and therefore, contributed to the lower volumes sold.

Revenues from the distribution of propane and related activities of $885.5 million for the year ended September 25, 2010 increased $21.4 million, or 2.5%, compared to $864.0 million for the year ended September 26, 2009, primarily as a result of higher average selling prices associated with higher product costs, partially offset by lower volumes, particularly in our commercial and industrial accounts. Average propane selling prices in fiscal 2010 increased 9.8% compared to the prior year due to higher product costs, thereby having a positive impact on revenues. This increase was partially offset by lower retail propane gallons sold in fiscal 2010 which decreased 26.0 million gallons, or 7.6%, to 317.9 million gallons from 343.9 million gallons in the prior year. The volume decline was primarily attributable to lower commercial and industrial volumes resulting from adverse economic conditions, an unfavorable weather pattern and, to a lesser extent, continued residential customer conservation. Lower volumes sold in the non-residential customer base accounted for approximately 60% of the decline in propane sales volume. Additionally, included within the propane segment are revenues from wholesale and other propane activities of $52.7 million in fiscal 2010, which increased $9.3 million compared to the prior year.

Revenues from the distribution of fuel oil and refined fuels of $135.1 million for the year ended September 25, 2010 decreased $24.5 million, or 15.4%, from $159.6 million in the prior year primarily due to lower volumes, partially offset by higher average selling prices. Fuel oil and refined fuels gallons sold in fiscal 2010 decreased 14.2 million gallons, or 24.7%, to 43.2 million gallons from 57.4 million gallons in the prior year. Lower volumes in our fuel oil and refined fuels segment were attributable to the aforementioned warmer average temperatures in the northeast region, as well as the impact of ongoing residential customer conservation driven by adverse economic conditions. Average selling prices in our fuel oil and refined fuels segment in fiscal 2010 increased 12.2% compared to the prior year due to higher product costs, thereby having a positive impact on revenues.

Revenues in our natural gas and electricity segment increased $0.8 million, or 1.0%, to $77.6 million for the year ended September 25, 2010 compared to $76.8 million in the prior year as a result of higher electricity volumes, partially offset by lower natural gas volumes. Revenues in our all other businesses decreased 9.7% to $38.6 million in fiscal 2010 from $42.7 million in the prior year, primarily due to reduced installation service activities as a result of the general market decline in residential and commercial construction and other adverse economic conditions.

Cost of Products Sold


										Percent
	Fiscal			Fiscal			Increase/			Increase/
(Dollars in thousands)	2010			2009			(Decrease)			(Decrease)
Cost of products sold
Propane	$	436,825		$	367,016		$	69,809			19.0	%
Fuel oil and refined fuels		92,037			104,634			(12,597	)		(12.0	)%
Natural gas and electricity		57,892			57,216			676			1.2	%
All other		11,697			11,519			178			1.5	%

Total cost of products sold	$	598,451		$	540,385		$	58,066			10.7	%


As a percent of total revenues		52.6	%		47.3	%

Cost of products sold increased $58.1 million, or 10.7%, to $598.5 million for the year ended September 25, 2010 compared to $540.4 million in the prior year due to higher average product costs and, to a lesser extent, the unfavorable impact of non-cash mark-to-market adjustments from our risk management activities in fiscal 2010 compared to the prior year, partially offset by lower volumes sold. Average posted prices for propane and fuel oil in fiscal 2010 were 46.3% and 26.1% higher, respectively, compared to the prior year. Cost of products sold in fiscal 2010 included a $5.4 million unrealized (non-cash) loss representing the net change in the fair value of derivative instruments during the period, compared to a $1.7 million unrealized (non-cash) gain in the prior year resulting in an increase of $7.1 million in cost of products sold in fiscal 2010 compared to the prior year ($1.3 million decrease reported within the propane segment and $8.4 million increase reported within the fuel oil and refined fuels segment).

Cost of products sold associated with the distribution of propane and related activities of $436.8 million for the year ended September 25, 2010 increased $69.8 million, or 19.0%, compared to the prior year. Higher propane product costs resulted in an increase of $89.2 million in cost of products sold in fiscal 2010 compared to the prior year. This increase was partially offset by lower propane volumes, which resulted in a decrease of $27.5 million in cost of products sold in fiscal 2010 compared to the prior year. Cost of products sold from wholesale and other propane activities increased $9.4 million compared to the prior year.

Cost of products sold associated with our fuel oil and refined fuels segment of $92.0 million for the year ended September 25, 2010 decreased $12.6 million, or 12.0%, compared to the prior year primarily due to lower volumes, offset to an extent by higher product costs and the unfavorable impact of non-cash mark-to-market adjustments from our risk management activities. Lower fuel oil volumes resulted in a decrease of $26.2 million in cost of products sold, and higher product costs resulted in an increase of $5.2 million in cost of products sold during fiscal 2010 compared to the prior year.

Cost of products sold in our natural gas and electricity segment of $57.9 million for the year ended September 25, 2010 increased $0.6 million, or 1.2%, compared to the prior year primarily due to higher electricity volumes, partially offset by lower natural gas volumes. Cost of products sold in our all other businesses of $11.7 million was relatively flat compared to the prior year.

For fiscal 2010, total cost of products sold as a percent of total revenues increased 5.3 percentage points to 52.6% from 47.3% in the prior year. The year-over-year increase in cost of products sold as a percentage of revenues was primarily attributable to the favorable margins reported in the prior year that were attributable to the declining commodity price environment during that period, which situation was not repeated in the current year due to the rising commodity price environment in the current year. The declining commodity price environment in the prior year favorably impacted our risk management activities in fiscal 2009, and contributed to a reduction in product costs that outpaced the decline in average selling prices. Conversely, the volatile and rising commodity price environment in the current fiscal year presented challenges in managing pricing and, as a result, average product costs increased at a faster pace than average selling prices in fiscal 2010.

Operating Expenses


	Fiscal			Fiscal						Percent
(Dollars in thousands)	2010			2009			(Decrease)			(Decrease)
Operating expenses	$	289,567		$	304,767		$	(15,200	)		(5.0	)%
As a percent of total revenues		25.5	%		26.7	%

Operating expenses of $289.6 million for the year ended September 25, 2010 decreased $15.2 million, or 5.0%, compared to $304.8 million in the prior year as a result of lower variable compensation associated with lower earnings, lower payroll and benefit related expenses resulting from operating efficiencies, and lower insurance costs.

General and Administrative Expenses


	Fiscal			Fiscal					Percent
(Dollars in thousands)	2010			2009			Increase		Increase
General and administrative expenses	$	61,656		$	57,044		$	4,612		8.1	%
As a percent of total revenues		5.4	%		5.0	%

General and administrative expenses of $61.6 million for the year ended September 25, 2010 increased $4.6 million, or 8.1%, compared to $57.0 million during the prior year as savings from lower variable compensation associated with lower earnings were more than offset by an unfavorable judgment in a legal matter and an increase in accruals for uninsured legal matters, as well as higher advertising costs.

Depreciation and Amortization


	Fiscal			Fiscal					Percent
(Dollars in thousands)	2010			2009			Increase		Increase
Depreciation and amortization	$	30,834		$	30,343		$	491		1.6	%
As a percent of total revenues		2.7	%		2.7	%

Depreciation and amortization expense of $30.8 million for the year ended September 25, 2010 increased $0.5 million, or 1.6%, compared to $30.3 million in the prior year primarily as a result of accelerating depreciation expense in the third quarter of fiscal 2010 for certain assets retired.

Interest Expense, net


	Fiscal			Fiscal						Percent
(Dollars in thousands)	2010			2009			(Decrease)			(Decrease)
Interest expense, net	$	27,397		$	38,267		$	(10,870	)		(28.4	)%
As a percent of total revenues		2.4	%		3.3	%

Net interest expense decreased $10.9 million, or 28.4%, to $27.4 million for the year ended September 25, 2010, compared to $38.3 million in the prior year primarily due to the reduction of $183.0 million in long-term borrowings during the second half of fiscal 2009, coupled with a lower effective interest rate for borrowings under our revolving credit facility. See Liquidity and Capital Resources below for additional discussion on the reduction and changes in long-term borrowings.

Loss on Debt Extinguishment

On September 9, 2009, we purchased $175.0 million aggregate principal amount of the 2013 Senior Notes through a cash tender offer. In connection with the repurchase, we recognized a loss on the extinguishment of debt of $4.6 million in the fourth quarter of fiscal 2009, consisting of $2.8 million for the tender premium and related fees, as well as the write-off of $1.8 million in unamortized debt origination costs and unamortized discount.

Net Income and Adjusted EBITDA

We reported net income of $115.3 million, or $3.26 per Common Unit, for the year ended September 25, 2010 compared to net income of $165.2 million, or $4.99 per Common Unit, in the prior year. Adjusted EBITDA amounted to $192.4 million, compared to $239.2 million for fiscal 2009.

Net income and EBITDA for fiscal 2010 were negatively impacted by certain items, including: (i) a loss on debt extinguishment of $9.5 million associated with the refinancing of senior notes completed during the second quarter; (ii) a non-cash pension settlement charge of $2.8 million during the fourth quarter; and (iii) a non-cash charge of $1.8 million during the third quarter to accelerate depreciation expense on certain assets taken out of service. Net income and EBITDA for fiscal 2009 included a loss on debt extinguishment of $4.6 million associated with the debt tender offer completed during the fourth quarter of fiscal 2009.

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:


	Year Ended
	September 25,			September 26,
(Dollars in thousands)	2010			2009

Net income	$	115,316		$	165,238
Add:
Provision for income taxes		1,182			2,486
Interest expense, net		27,397			38,267
Depreciation and amortization		30,834			30,343

EBITDA		174,729			236,334
Unrealized (non-cash) losses (gains) on changes in fair value of derivatives		5,400			(1,713	)
Loss on debt extinguishment		9,473			4,624
Pension settlement charge		2,818			—

Adjusted EBITDA		192,420			239,245
Add (subtract):
Provision for income taxes — current		(1,182	)		(1,101	)
Interest expense, net		(27,397	)		(38,267	)
Unrealized (non-cash) (losses) gains on changes in fair value of derivatives		(5,400	)		1,713
Compensation cost recognized under Restricted Unit Plans		4,005			2,396
Loss (gain) on disposal of property, plant and equipment, net		38			(650	)
Changes in working capital and other assets and liabilities		(6,687	)		43,215


Net cash provided by operating activities	$	155,797		$	246,551

Liquidity and Capital Resources

Analysis of Cash Flows

Operating Activities. Net cash provided by operating activities for fiscal 2011 amounted to $132.8 million, a decrease of $23.0 million compared to the prior year. The decrease was attributable to a $10.6 million decrease in earnings, after adjusting for non-cash items in both periods, coupled with a $12.4 million increase in our investment in working capital as a result of the increase in propane and fuel oil product costs. Despite the year-over-year increase in working capital requirements, we continued to fund working capital through cash on hand without the need to access the revolving credit facility.

Investing Activities. Net cash used in investing activities of $19.5 million for fiscal 2011 consisted of capital expenditures of $22.3 million (including $10.2 million for maintenance expenditures and $12.1 million to support the growth of operations) and business acquisitions of $3.2 million, partially offset by the net proceeds from the sale of property, plant and equipment of $6.0 million. Net cash used in investing activities of $30.1 million for fiscal 2010 consisted of capital expenditures of $19.1 million (including $9.7 million for maintenance expenditures and $9.4 million to support the growth of operations), partially offset by the net proceeds from the sale of property, plant and equipment of $3.5 million.

Financing Activities. Net cash used in financing activities for fiscal 2011 of $120.6 million reflects quarterly distributions to Unitholders at a rate of $0.85 per Common Unit paid in respect of the fourth quarter of fiscal 2010 and $0.8525 per Common Unit paid in respect of the first, second and third quarters of fiscal 2011.

Net cash used in financing activities for fiscal 2010 of $132.0 million reflects $118.3 million in quarterly distributions to Unitholders at a rate of $0.83 per Common Unit paid in respect of the fourth quarter of fiscal 2009, $0.835 per Common Unit paid in respect of the first quarter of fiscal 2010, $0.84 per Common Unit paid in respect of the second quarter of fiscal 2010, and $0.845 per Common Unit paid in respect of the third quarter of fiscal 2010. In addition, financing activities for fiscal 2010 also reflects the repurchase of $250.0 million aggregate principal amount of our 6.875% senior notes due 2013 for $256.5 million (including repurchase premiums and fees), which was substantially funded by the net proceeds of $247.8 million from the issuance of 7.375% senior notes due 2020, as well as the $5.0 million payment of debt issuance costs associated with the issuance of the 2020 senior notes.

Equity Offering

On August 10, 2009, we sold 2,200,000 Common Units in a public offering (the “Equity Offering”) at a price of $41.50 per Common Unit, realizing proceeds of $86.7 million, net of underwriting commissions and other offering expenses. On August 24, 2009, we announced that the underwriters had given notice of their exercise of their over-allotment option, in part, to acquire 230,934 Common Units at the Equity Offering price of $41.50 per Common Unit. Net proceeds from the over-allotment exercise amounted to $9.2 million. The aggregate net proceeds from the Equity Offering of $95.9 million were used, along with cash on hand, to fund the purchase of $175.0 million aggregate principal amount of our 6.875% senior notes due 2013.

Summary of Long-Term Debt Obligations and Revolving Credit Lines

On March 23, 2010, we completed a public offering of $250.0 million in aggregate principal amount of 7.375% senior notes due 2020 (the “2020 Senior Notes”). The 2020 Senior Notes were issued at 99.136% of the principal amount. The net proceeds from the issuance, along with cash on hand, were used to repurchase the 6.875% senior notes due 2013 (the “2013 Senior Notes”) on March 23, 2010 through a redemption and tender offer. In connection with the repurchase of the 2013 Senior Notes, we recognized a loss on the extinguishment of debt of $9.5 million in the second quarter of fiscal 2010, consisting of $7.2 million for the repurchase premium and related fees, as well as the write-off of $2.3 million in unamortized debt origination costs and unamortized discount.

As of September 24, 2011, our long-term borrowings and revolving credit lines consist of the 2020 Senior Notes and a $250.0 million senior secured revolving credit facility at the Operating Partnership level (the “Revolving Credit Facility”). The Revolving Credit Facility was executed on June 26, 2009 and replaced the Operating Partnership’s previous credit facility which, as amended, provided for a $108.0 million term loan (the “Term Loan”) and a separate $175.0 million working capital facility both of which were scheduled to mature in March 2010. Borrowings under the Revolving Credit Facility may be used for general corporate purposes, including working capital, capital expenditures and acquisitions until maturity on June 25, 2013. Our Operating Partnership has the right to prepay loans under the Revolving Credit Facility, in whole or in part, without penalty at any time prior to maturity. At closing, the Operating Partnership borrowed $100.0 million under the Revolving Credit Facility and, with cash on hand, repaid the $108.0 million then outstanding under the Term Loan and terminated the previous credit agreement. We have standby letters of credit issued under the Revolving Credit Facility in the aggregate amount of $54.9 million primarily in support of retention levels under our self-insurance programs, which expire periodically through April 15, 2012. Therefore, as of September 24, 2011 we had available borrowing capacity of $95.1 million under the Revolving Credit Facility.

The 2020 Senior Notes mature on March 15, 2020 and require semi-annual interest payments in March and September. We are permitted to redeem some or all of the 2020 Senior Notes any time at redemption prices specified in the indenture governing the notes. In addition, the 2020 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 change of control is followed by a rating decline (a decrease in the rating of the notes by either Moody’s Investors Service or Standard and Poor’s Rating Group by one or more gradations) within 90 days of the consummation of the change of control.

Borrowings under the Revolving Credit Facility bear interest at prevailing interest rates based upon, at our Operating Partnership’s option, LIBOR plus the applicable margin or the base rate, defined as the higher of the Federal Funds Rate plus ¹/2 of 1%, the agent bank’s prime rate, or LIBOR plus 1%, plus in each case the applicable margin. The applicable margin is dependent upon our ratio of total debt to EBITDA on a consolidated basis, as defined in the Revolving Credit Facility. As of September 24, 2011, the interest rate for the Revolving Credit Facility was approximately 3.25%. The interest rate and the applicable margin will be reset at the end of each calendar quarter.

On July 31, 2009, our Operating Partnership entered into an interest rate swap agreement with an effective date of March 31, 2010 and a termination date of June 25, 2013. Under the interest rate swap agreement, our Operating Partnership will pay a fixed interest rate of 3.12% to the issuing lender on the notional principal amount outstanding, effectively fixing the LIBOR portion of the interest rate at 3.12%. In return, the issuing lender will pay to our Operating Partnership a floating rate, namely LIBOR, on the same notional principal amount. This interest rate swap agreement replaced the previous interest rate swap agreement which terminated on March 31, 2010.

The Revolving Credit Facility and the 2020 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. The Revolving Credit Facility contains certain financial covenants (a) requiring the consolidated interest coverage ratio, as defined, at the Partnership level to be not less than 2.5 to 1.0 as of the end of any fiscal quarter; (b) prohibiting the total consolidated leverage ratio, as defined, at the Partnership level from being greater than 4.5 to 1.0 as of the end of any fiscal quarter; and (c) prohibiting the senior secured consolidated leverage ratio, as defined, of the Operating Partnership from being greater than 3.0 to 1.0 as of the end of any fiscal quarter. Under the 2020 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 the Partnership’s consolidated fixed charge coverage ratio, as defined, is greater than 1.75 to 1. We were in compliance with all covenants and terms of the 2020 Senior Notes and the Revolving Credit Facility as of September 24, 2011.

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 20, 2011, we announced a quarterly distribution of $0.8525 per Common Unit, or $3.41 on an annualized basis, in respect of the fourth quarter of fiscal 2011 payable on November 8, 2011 to holders of record on November 1, 2011.

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 2011, 2010 or 2009. As of September 24, 2011 and September 25, 2010 the plan’s projected benefit obligation exceeded the fair value of plan assets by $26.2 million and $17.7 million, respectively. As a result, the funded status of the defined benefit pension plan declined $8.5 million during fiscal 2011, which was primarily attributable to an increase in the present value of the benefit obligation due to a general decrease in market interest rates, partially offset by a positive return on plan assets during fiscal 2011. The funded status of pension and other postretirement benefit plans are recognized as an asset or liability on our balance sheets and the changes in the funded status are recognized in comprehensive income (loss) in the year the changes occur.

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. The Benefits Committee employs a liability driven investment strategy, which seeks to increase the correlation of the plan’s assets and liabilities to reduce the volatility of the plan’s funded status. The execution of this strategy has resulted in an asset allocation that is largely comprised of fixed income securities. A liability driven investment strategy is intended to reduce investment risk and, over the long-term, generate returns on plan assets that largely fund the annual interest on the accumulated benefit obligation. However, as we experienced in fiscal 2011 and fiscal 2010, significant declines in interest rates relevant to our benefit obligations, or poor performance in the broader capital markets in which our plan assets are invested, could have an adverse impact on the funded status of the defined benefit pension plan. For purposes of measuring the projected benefit obligation as of September 24, 2011 and September 25, 2010, we used a discount rate of 4.375% and 4.75%, respectively, reflecting current market rates for debt obligations of a similar duration to our pension obligations.

During fiscal 2010, lump sum settlement payments of $7.9 million exceeded the interest cost component of the net periodic pension cost. As a result, we recorded a non-cash settlement charge of $2.8 million during the fourth quarter of fiscal 2010 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. During fiscal 2011 and fiscal 2009, the amount of the pension benefit obligation settled through lump sum payments did not exceed the settlement threshold; therefore, a settlement charge was not required to be recognized for fiscal 2011 or fiscal 2009. Additional pension settlement charges may be required in future periods depending on the level of lump sum benefit payments made in future periods.

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 our 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 24, 2011.


											Fiscal
	Fiscal		Fiscal		Fiscal		Fiscal		Fiscal		2017 and
(Dollars in thousands)	2012		2013		2014		2015		2016		thereafter

Long-term debt obligations	$	—	$	100,000	$	—	$	—	$	—	$	250,000
Interest payments		25,033		25,033		18,438		18,438		18,438		64,531
Operating lease obligations (a)		15,836		13,346		11,540		8,480		4,993		4,709
Self-insurance obligations (b)		13,188		10,706		8,212		4,900		3,110		12,724
Other contractual obligations (c)		7,870		4,949		2,431		1,777		2,255		18,783

Total	$	61,927	$	154,034	$	40,621	$	33,595	$	28,796	$	350,747


(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 amounts to $4.2 million, $3.5 million, $2.7 million, $1.3 million, $0.9 million and $4.9 million for each of the next five fiscal years and thereafter, respectively, and are included in other assets on the consolidated balance sheet.

(c)		These amounts are included in our consolidated balance sheet and primarily include payments for postretirement and long-term incentive benefits as well as periodic settlements of our interest rate swap agreement.

Additionally, we have standby letters of credit in the aggregate amount of $54.9 million, in support of retention levels under our casualty insurance programs and certain lease obligations, which expire periodically through April 15, 2012.

Operating Leases

We lease certain property, plant and equipment for various periods under noncancelable operating leases, including 63% of our vehicle fleet, approximately 34% of our customer service centers and portions of our information systems equipment. Rental expense under operating leases was $18.9 million, $17.6 million and $17.3 million for fiscal 2011, 2010 and 2009, respectively. Future minimum rental commitments under noncancelable operating lease agreements as of September 24, 2011 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 2018, 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 $9.7 million. The fair value of residual value guarantees for outstanding operating leases was de minimis as of September 24, 2011 and September 25, 2010.

Recently Issued Accounting Pronouncements

In May 2011, the Financial Accounting Standards Board (“FASB”) issued an accounting standard update to provide guidance on achieving a consistent definition of and common requirements for fair value measurement and related disclosure requirements in US GAAP. The new guidance requires quantitative information about unobservable inputs, valuation processes and sensitivity analysis associated with fair value measurements categorized within Level 3 of the fair value hierarchy, and is effective prospectively during interim and annual periods beginning after December 15, 2011, which will be the second quarter of our 2012 fiscal year. Early adoption is not permitted. No material impact is expected on our consolidated financial position, results of operations and cash flows.

In June 2011, the FASB issued an accounting standard update to provide guidance on increasing the prominence of items reported in other comprehensive income. This update eliminates the option to present components of other comprehensive income as part of the statement of partners’ capital and requires that the total of comprehensive income, the components of net income and the components of other comprehensive income be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. Early adoption of this updated guidance is permitted, and it becomes effective retrospectively during interim and annual periods beginning after December 15, 2011, which will be the second quarter of our 2012 fiscal year. This update does not change the items that must be reported in other comprehensive income.

In September 2011, the FASB issued a revised accounting standard allowing companies to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If, as a result of the qualitative assessment, it is more likely than not that the fair value of a reporting unit is less than its carrying amount, a more detailed two-step goodwill impairment test would be performed to identify a potential goodwill impairment and measure the amount of loss to be recognized, if any. The standard will be effective for annual and interim goodwill impairment tests performed after December 31, 2011, with early adoption permitted. The adoption of this standard is not expected to impact the Partnership’s financial position, results of operations or 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, 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, supply and demand dynamics 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 accounting rules for derivative instruments and hedging activities, qualify for and are designated as normal purchase or normal sale contracts. Such contracts are exempted from fair value accounting 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 and, in certain instances, over-the-counter option contracts (collectively, “derivative instruments”) to manage the price risk associated with 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 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 market 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 derivative instruments will typically offset losses or gains on the physical inventory once the product is sold to customers at market prices.

Futures are traded with brokers of the NYMEX and 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

Exchange-traded futures and option contracts 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 borrowings bear interest at prevailing interest rates based upon, at the Operating Partnership’s option, LIBOR, plus an applicable margin or the base rate, defined as the higher of the Federal Funds Rate plus ¹/2 of 1% or the agent bank’s prime rate, or LIBOR plus 1%, plus the applicable margin. The applicable margin is dependent on the level of the Partnership’s total leverage (the total ratio of debt to EBITDA). 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 interest rate swap agreements. The interest rate swaps have been designated as a cash flow hedge. Changes in the fair value of the interest rate swaps are recognized in other comprehensive income (“OCI”) until the hedged item is recognized in earnings. At September 24, 2011, the fair value of the interest rate swaps was $4.6 million representing an unrealized loss and is included within other current liabilities and other liabilities, as applicable, with a corresponding debit in OCI.

Derivative Instruments and Hedging Activities

All of our derivative instruments are reported on the balance sheet 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 earnings 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 are immediately recognized in earnings. 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, are recorded in earnings as they occur. Cash flows associated with derivative instruments are reported as operating activities within the consolidated statement of cash flows.

Sensitivity Analysis

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

The fair value of open positions as of September 24, 2011.

The market prices for the underlying commodities used to determine A. above were adjusted adversely by a hypothetical 10% change and compared to the fair value 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 open futures and option contracts as of September 24, 2011 indicates a reduction in potential future net gains of $1.1 million as of September 24, 2011. 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.


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, fuel oil and other refined fuel and natural gas businesses, 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 2011
Revenues	$	328,307		$	464,102		$	216,563		$	181,580		$	1,190,552
Cost of products sold		186,504			259,832			125,175			107,208			678,719
Severance charges		—			2,000			—			—			2,000
Operating income (loss)		50,341			107,233			353			(14,699	)		143,228
Net income (loss)		43,129			100,316			(6,787	)		(21,692	)		114,966
Net income (loss) per common unit — basic (b)		1.22			2.82			(0.19	)		(0.61	)		3.24
Net income (loss) per common unit — diluted (b)		1.21			2.81			(0.19	)		(0.61	)		3.22

Cash provided by (used in)
Operating activities		(4,858	)		54,696			60,003			22,945			132,786
Investing activities		(6,390	)		(3,194	)		(5,285	)		(4,636	)		(19,505	)
Financing activities		(30,062	)		(30,177	)		(30,194	)		(30,203	)		(120,636	)
EBITDA (c)	$	58,521		$	115,687		$	10,023		$	(5,375	)	$	178,856
Adjusted EBITDA (c)	$	60,094		$	113,564		$	10,336		$	(4,569	)	$	179,425
Retail gallons sold
Propane		86,286			114,034			54,629			43,953			298,902
Fuel oil and refined fuels		11,393			16,249			5,621			3,978			37,241

Fiscal 2010
Revenues	$	301,432		$	469,163		$	198,070		$	168,029		$	1,136,694
Cost of products sold		150,366			248,459			106,627			92,999			598,451
Pension settlement charge		—			—			—			2,818			2,818
Operating income (loss)		55,757			114,797			555			(17,741	)		153,368
Loss on debt extinguishment (a)		—			9,473			—			—			9,473
Net income (loss)		48,375			98,388			(6,616	)		(24,831	)		115,316
Net income (loss) per common unit — basic (b)		1.37			2.78			(0.19	)		(0.70	)		3.26
Net income (loss) per common unit — diluted (b)		1.36			2.76			(0.19	)		(0.70	)		3.24

Cash provided by (used in)
Operating activities		(14,726	)		72,057			72,393			26,073			155,797
Investing activities		(3,663	)		(3,487	)		(13,614	)		(9,347	)		(30,111	)
Financing activities		(29,288	)		(43,154	)		(29,665	)		(29,844	)		(131,951	)
EBITDA (c)	$	62,841		$	112,466		$	9,423		$	(10,001	)	$	174,729
Adjusted EBITDA (c)	$	66,249		$	123,671		$	9,142		$	(6,642	)	$	192,420
Retail gallons sold
Propane		89,981			124,457			56,037			47,431			317,906
Fuel oil and refined fuels		13,056			18,381			6,631			5,128			43,196


(a)		During the second quarter of fiscal 2010 we completed the issuance of $250.0 million of 7.375% senior notes maturing in March 2020 to replace the previously existing 6.875% senior notes that were set to mature in December 2013. In connection with the refinancing, we recognized a loss on debt extinguishment of $9.5 million, consisting of $7.2 million for the repurchase premium and related fees, as well as the write-off of $2.2 million in unamortized debt origination costs and unamortized discount.


(b)		Basic net income (loss) per Common Unit is computed by dividing net income (loss) by the weighted average number of outstanding Common Units, and restricted units granted under the restricted unit plans to retirement-eligible grantees. Computations of diluted net income per Common Unit are performed by dividing net income by the weighted average number of outstanding Common Units and unvested restricted units granted under our restricted unit plans. Diluted loss per Common Unit for the periods where a net loss was reported does not include unvested restricted units granted under our restricted unit plans as their effect would be anti-dilutive.

(c)		EBITDA represents net income before deducting interest expense, income taxes, depreciation and amortization. Adjusted EBITDA represents EBITDA excluding the unrealized net gain or loss from mark-to-market activity for derivative instruments, loss on debt extinguishment, pension settlement charge and severance charges. Our management uses EBITDA and Adjusted EBITDA as measures of liquidity and we are including them because we believe that they provide 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 Adjusted EBITDA as the performance target. Moreover, our revolving credit agreement requires us to use Adjusted EBITDA as a component in calculating our leverage and interest coverage ratios. EBITDA and Adjusted EBITDA are not recognized terms under US GAAP and should not be considered as an alternative to net income or net cash provided by operating activities determined in accordance with US GAAP. Because EBITDA and Adjusted EBITDA as determined by us excludes some, but not all, items that affect net income, they may not be comparable to EBITDA and Adjusted 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 (used in) provided by operating activities (amounts in thousands):


	First			Second			Third			Fourth			Total
Fiscal 2011	Quarter			Quarter			Quarter			Quarter			Year
Net income (loss)	$	43,129		$	100,316		$	(6,787	)	$	(21,692	)	$	114,966
Add:
Provision for income taxes		366			98			273			147			884
Interest expense, net		6,846			6,819			6,867			6,846			27,378
Depreciation and amortization		8,180			8,454			9,670			9,324			35,628

EBITDA		58,521			115,687			10,023			(5,375	)		178,856
Unrealized (non-cash) losses (gains) on changes in fair value of derivatives		1,573			(4,123	)		313			806			(1,431	)
Severance charges		—			2,000			—			—			2,000

Adjusted EBITDA		60,094			113,564			10,336			(4,569	)		179,425
Add (subtract):
Provision for income taxes		(366	)		(98	)		(273	)		(147	)		(884	)
Interest expense, net		(6,846	)		(6,819	)		(6,867	)		(6,846	)		(27,378	)
Unrealized (non-cash) (losses) gains on changes in fair value of derivatives		(1,573	)		4,123			(313	)		(806	)		1,431
Severance charges		—			(2,000	)		—			—			(2,000	)
Compensation cost recognized under Restricted Unit Plans		1,332			1,067			737			786			3,922
(Gain) loss on disposal of property, plant and equipment, net		(299	)		(2,612	)		67			72			(2,772	)
Changes in working capital and other assets and liabilities		(57,200	)		(52,529	)		56,316			34,455			(18,958	)


Net cash (used in) provided by operating activities	$	(4,858	)	$	54,696		$	60,003		$	22,945		$	132,786


	First			Second			Third			Fourth			Total
Fiscal 2010	Quarter			Quarter			Quarter			Quarter			Year
Net income (loss)	$	48,375		$	98,388		$	(6,616	)	$	(24,831	)	$	115,316
Add:
Provision for income taxes		199			328			363			292			1,182
Interest expense, net		7,183			6,608			6,808			6,798			27,397
Depreciation and amortization		7,084			7,142			8,868			7,740			30,834

EBITDA		62,841			112,466			9,423			(10,001	)		174,729
Unrealized (non-cash) losses (gains) on changes in fair value of derivatives		3,408			1,732			(281	)		541			5,400
Loss on debt extinguishment		—			9,473			—			—			9,473
Pension settlement charge		—			—			—			2,818			2,818

Adjusted EBITDA		66,249			123,671			9,142			(6,642	)		192,420
Add (subtract):
Provision for income taxes		(199	)		(328	)		(363	)		(292	)		(1,182	)
Interest expense, net		(7,183	)		(6,608	)		(6,808	)		(6,798	)		(27,397	)
Unrealized (non-cash) (losses) gains on changes in fair value of derivatives		(3,408	)		(1,732	)		281			(541	)		(5,400	)
Compensation cost recognized under Restricted Unit Plans		992			1,025			1,136			852			4,005
(Gain) loss on disposal of property, plant and equipment, net		(427	)		293			283			(111	)		38
Changes in working capital and other assets and liabilities		(70,750	)		(44,264	)		68,722			39,605			(6,687	)


Net cash (used in) provided by operating activities	$	(14,726	)	$	72,057		$	72,393		$	26,073		$	155,797


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 24, 2011. 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 24, 2011.

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 24, 2011, 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.

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.

The Partnership’s management has assessed the effectiveness of the Partnership’s internal control over financial reporting as of September 24, 2011. In making this assessment, the Partnership used the criteria established by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in “Internal Control-Integrated Framework.” These criteria are in the areas of control environment, risk assessment, control activities, information and communication, and monitoring. The Partnership’s assessment included documenting, evaluating and testing the design and operating effectiveness of its internal control over financial reporting.

Based on the Partnership’s assessment, as described above, management has concluded that, as of September 24, 2011, the Partnership’s internal control over financial reporting was effective.

Our independent registered public accounting firm, PricewaterhouseCoopers LLP, issued an attestation report dated November 23, 2011 on the effectiveness of our internal control over financial reporting, which is included herein.


ITEM 9B.		OTHER INFORMATION

None.

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 six Supervisors, who serve on the Board of Supervisors pursuant to the terms of the Partnership Agreement. Under the current Partnership Agreement, all Supervisors are elected by the Unitholders for three-year terms. All six current Supervisors were elected to their current three-year terms at the Tri-Annual Meeting held on July 22, 2009.

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, or which may be required to be disclosed pursuant to Item 404(a) of Regulation S-K adopted by the Securities and Exchange Commission, 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.

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 independent and (with the exception of Ms. Swift) are audit committee financial experts 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. Logan, Chairman of the Board, 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 23, 2011. 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
Michael J. Dunn, Jr.		62	President and Chief Executive Officer; Member of the Board of Supervisors
Michael A. Stivala		42	Chief Financial Officer
Michael M. Keating		58	Senior Vice President — Administration
A. Davin D’Ambrosio		47	Vice President and Treasurer
Paul Abel		58	Vice President, General Counsel and Secretary
Mark Anton, II		54	Vice President — Business Development
Steven C. Boyd		47	Vice President — Field Operations
Douglas T. Brinkworth		50	Vice President — Product Supply
Neil Scanlon		46	Vice President — Information Services
Mark Wienberg		49	Vice President — Operational Support and Analysis
Michael Kuglin		41	Vice President and Chief Accounting Officer
Harold R. Logan, Jr.		67	Member of the Board of Supervisors (Chairman)
John Hoyt Stookey		81	Member of the Board of Supervisors (Chairman of the Compensation Committee)
Dudley C. Mecum		76	Member of the Board of Supervisors
John D. Collins		73	Member of the Board of Supervisors (Chairman of the Audit Committee)
Jane Swift		46	Member of the Board of Supervisors

Mr. Dunn has served as President since May 2005 and as Chief Executive Officer since September 2009. From June 1998 until May 2005 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. Dunn is the sole member of the General Partner.

Mr. Dunn’s qualifications to sit on our Board include his more than 14 years of experience in the propane industry, including as our President for the past 6 years and Chief Executive Officer for the past 2 years, which day to day leadership roles have provided him with intimate knowledge of our operations.

Mr. Stivala has served as Chief Financial Officer since November 2009, and 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. Keating has served as Senior Vice President — Administration since July 2009. From July 1996 to that date he was Vice President — Human Resources and Administration. He previously held senior human resource positions at Hanson Industries (the United States management division of Hanson plc, a global diversified industrial conglomerate) and Quantum Chemical Corporation (“Quantum”), a predecessor of the Partnership.

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 — Field Operations (formerly 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 — Product Supply (formerly 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 product supply area.

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. Wienberg has served as Vice President — Operational Support and Analysis (formerly 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. Kuglin has served as Vice President and Chief Accounting Officer since November 2011. Prior to that he was Controller and Chief Accounting Officer since November 2009 and 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. Mr. Logan is a Co-Founder and, from 2006 to the present has been serving as a 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 Cimarex Energy Co., Graphic Packaging Holding Company and Hart Energy Publishing LLP, and, until it was sold in 2007, served as a Director of The Houston Exploration Company.

Over the past 40 years, Mr. Logan’s education, investment banking/venture capital experience and business/financial management experience have provided him with a comprehensive understanding of business and finance. Most of Mr. Logan’s business experience has been in the energy industry, both in investment banking and as a senior financial officer and director of publicly-owned energy companies. Mr. Logan’s expertise and experience have been relevant to his responsibilities of providing oversight and advice to the managements of public companies, and is of particular benefit in his role as our Chairman. Since 1996, Mr. Logan has been a director of nine public companies and has served on audit, compensation and governance committees.

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) and has also served on the Board of Directors of The Clark Foundation, The Robert Sterling Clark Foundation and The Berkshire Taconic Community Foundation.

Mr. Stookey’s qualifications to sit on our Board include his extensive experience as Chief Executive Officer of 4 corporations (including a predecessor of the Partnership) and his many years of service as a director of publicly-owned corporations and non-profit organizations.

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. Until 2007, Mr. Mecum was a director of Citigroup, Inc.

Mr. Mecum’s qualifications to sit on our Board include his 20 years in public accounting, rising to the level of Vice Chairman of KPMG LLP, a public accounting firm, his service as Assistant Secretary of the Army for Installations and Logistics and his 15 years of service overseeing or managing various companies. Mr. Mecum has over 20 years of service as a director of various publicly-owned companies.

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 and Mrs. Fields Original Cookies, Inc. and, until recently, was a Director of Columbia Atlantic Funds.

Mr. Collins’ qualifications to sit on our Board, and serve as Chairman of its Audit Committee, include his 40 years of experience in public accounting, including 31 years as a partner supervising the audits of public companies. Mr. Collins has served on a number of AICPA and international accounting and auditing standards bodies.

Ms. Swift has served as a Supervisor since April 2007. She is currently the CEO of Middlebury Interactive Languages, LLC, a marketer of world language products. From 2010 through July 2011, Ms. Swift served as Senior Vice President of ConnectEDU Inc., a private education technology company. In 2007, she founded WNP Consulting, LLC, a provider of expert advice and guidance to early stage education companies. From 2003 to 2006 she was a General Partner at Arcadia Partners, a venture capital firm focused on the education industry. She has previously served on the boards of K12, Inc. and Animated Speech Company and currently serves on the boards of 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.

Ms. Swift’s qualifications to sit on our Board include her strong skills in public policy and government relations and her extensive knowledge of regulatory matters arising from her 15 years in state government.

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 2011.

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. A copy of our Code of Ethics and our Code of Business Conduct is 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. A copy of our Corporate Governance Guidelines is 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. A copy of our Audit Committee Charter is 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. A copy of our Compensation Committee Charter is 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. Dunn submitted his Annual CEO Certification for our 2011 fiscal year to the NYSE without qualification.


ITEM 11.		EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

This Compensation Discussion and Analysis explains our executive compensation philosophy, policies and practices with respect to the following executive officers of the Partnership (the “named executive officers”): the President and Chief Executive Officer, the Chief Financial Officer and the other three 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 a performance-based annual bonus plan;

	•		Long-Term Incentive Plan awards; and

	•		Awards of restricted units under the Restricted Unit Plans.

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 executive officers to implement activities and practices conducive to sustainable, profitable growth; and

	•		Providing our executive officers with restricted units in order 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, our Senior Vice President of Administration 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 total compensation package, the Committee is provided with benchmarking data for comparison. 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 provided to the Committee for the 2011 fiscal year was derived from the Mercer Human Resource Consulting, Inc. (“Mercer”) Benchmark Database containing information obtained from surveys of over 2,269 organizations and approximately 201 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 the Partnership. The benchmarking information used by the Committee consisted of organizations included in the Mercer database that report median annual revenues of between $1.4 billion and $3.8 billion per year.

The Committee believes that using the Mercer database to evaluate “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 similarly skilled employees. 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 executives in vastly different economic environments.

Conversely, for the reasons set forth under the subheading “2003 Long-Term Incentive Plan” below, the Committee decided to include other propane marketers, structured as publicly traded partnerships, in the peer group it selected for the 2003 Long-Term Incentive Plan. 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 relative to the unit performance of a peer group of eleven other master limited partnerships over a three-year measurement period.

In making their decisions regarding executive compensation packages for the coming fiscal year, the members of the Committee review the total cash compensation opportunities that were provided to our executive officers during the just completed fiscal year. Each executive officer’s “total cash compensation opportunity” consists of base salary, an annual cash bonus, and 2003 Long-Term Incentive Plan awards. The Committee then compares each executive officer’s total cash compensation opportunity to the total mean cash compensation opportunity for the parallel position in the Mercer database. By focusing on each executive officer’s total cash compensation opportunity as a whole, instead of on single components of compensation such as base salary, when it met on November 9, 2010, the Committee created fiscal 2011 compensation packages for our executive officers that emphasized the performance-based components of compensation.

Role of Executive Officers and the Compensation Committee in the Compensation Process

The Committee establishes and enforces our general compensation philosophy in consultation with our President and Chief Executive Officer. The role of our President and 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 Senior Vice President of Administration, our President and Chief Executive Officer presents 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 the Mercer database was to provide the Committee with benchmarking data. Therefore, neither our President and Chief Executive Officer nor our Senior Vice President of Administration 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 Senior Vice President of Administration, 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 Senior Vice President of Administration.

Among other duties, the Committee has overall responsibility for:

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

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

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 or her position. The base salary for each executive officer is the only fixed component of compensation. All other cash 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 2011 (as determined at the Committee’s November 9, 2010 meeting).


				Cash			Long-Term
	Base Salary			Bonus Target			Incentive

Michael J. Dunn, Jr.		40	%		40	%		20	%
Michael A. Stivala		45	%		36	%		19	%
Steven C. Boyd		45	%		36	%		19	%
Mark Wienberg		45	%		36	%		19	%
Douglas T. Brinkworth		45	%		36	%		19	%

In allocating compensation among these components, 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 at least 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 with the Partnership, individual performance and years of experience in his or her 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 Restricted Unit Plans (see below for a description of these plans). As a result, different weights 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, 50% performance-based. In order to align the interests of senior management with the interests of our Unitholders, we consider it requisite to accentuate the performance-based elements of the compensation packages that we provide to these individuals.

Base Salary

Base salaries for the named executive officers and all of our other executive officers, are reviewed and approved annually by the Committee. In order to determine base salary increases, the Committee’s practice is to compare each executive officer’s base salary with the corresponding mean salary provided in the Mercer database. The Committee usually determines 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. In accordance with this process, and the philosophy described above, the Committee did not adjust the base salaries of the named executive officers during fiscal 2011; instead, the Committee decided to increase each of the bonus target percentages of each of the named executive officers (with the exception of Mr. Dunn’s, whose bonus target percentage was already at 100%). The Committee reasoned that this action would further align the interests of management with the interests of our Unitholders. In the event of a promotion, a significant increase in an executive officer’s responsibilities, or a new hire, it is the Committee’s practice to review that executive officer’s base salary at that time and take such action as the Committee deems warranted.

The total base salary paid to each named executive officer in fiscal 2011 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 objective performance provisions of our annual cash bonus plan.

The terms of our annual cash bonus plan provide for cash payments of a specified percentage (which, in fiscal 2011, ranged from 80% to 100%) of our named executive officers’ annual base salaries (“target cash bonus”) if, for the fiscal year, actual cash bonus plan EBITDA equals the Partnership’s budgeted EBITDA. For purposes of calculating cash bonus plan EBITDA, the Committee customarily adjusts both budgeted and actual EBITDA (as defined in Item 6 in this annual report on Form 10-K) 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. Under the previous annual cash bonus plan, executive officers had the opportunity to earn between 90% and 110% of their target cash bonuses; however, beginning with fiscal 2011, executive officers have the opportunity to earn between 60% and 120% of their target cash bonuses, depending upon the Partnership’s EBITDA performance in the fiscal year. Under the existing 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 120% of the target cash bonus even if actual cash bonus plan EBITDA is more than 120% of budgeted cash bonus plan EBITDA.

Although our annual cash bonus plan is generally administered using the formula described above, the Committee may exercise its broad discretionary powers to decrease or increase the annual cash bonus paid to a particular executive officer, upon the recommendation of our President and Chief Executive Officer, or the executive officers as a group, when the Committee recognizes that an adjustment is warranted. During fiscal 2011, fiscal 2010 and fiscal 2009, no such discretionary adjustments were made to the annual cash bonuses earned by our executives.

For fiscal 2011, our budgeted cash bonus plan EBITDA was $195 million (“Budgeted EBITDA”). Our actual cash bonus plan EBITDA was such that each of our executive officers earned 60% of his or her target cash bonus. The following table provides the fiscal 2011 budgeted cash bonus plan EBITDA targets that were established at the November 9, 2010 Compensation Committee meeting:


			Hypothetical Fiscal 2011
			Cash Bonus Plan EBITDA			Target Bonus Percentage that
Hypothetical Fiscal 2011			Expressed as a			would have been Earned if
Cash Bonus Plan EBITDA			Percentage of			Actual Cash Bonus Plan
Results			Budgeted Cash Bonus Plan			EBITDA Equaled the Figure
(in Millions)			EBITDA			in the First Column
$	234.0			120	%		120	%
$	214.5			110	%		110	%
$	195.0	⁽¹⁾		100	%		100	%
$	185.3			95	%		90	%
$	175.5			90	%		60	%


(1)		Budgeted cash bonus plan EBITDA for fiscal 2011.

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 fiscal 2011 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 2011 are summarized as follows:


	2011 Target Cash
	Bonus as a % of			2011 Target Cash		2011 Actual Cash
Name	Base Salary			Bonus		Bonus Earned
Michael J. Dunn, Jr.		100	%	$	475,000	$	285,000
Michael A. Stivala		80	%	$	220,000	$	132,000
Steven C. Boyd		80	%	$	216,000	$	129,600
Mark Wienberg		80	%	$	200,000	$	120,000
Douglas T. Brinkworth		80	%	$	196,000	$	117,600

For purposes of establishing the cash bonus targets for fiscal 2011, the Committee reviewed and approved our fiscal 2011 budgeted cash bonus plan EBITDA at its November 9, 2010 meeting. The budgeted cash bonus plan EBITDA is developed annually using a bottom-up process factoring in reasonable growth targets from the prior year’s 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 have the opportunity to earn between 60% and 120% of their target cash bonuses. Over the past three years, our actual cash bonus plan EBITDA was such that each of our executive officers earned 60%, 100%, and 110% of their respective target cash bonus for fiscal 2011, fiscal 2010 and fiscal 2009, respectively.

2003 Long-Term Incentive Plan

At the beginning of fiscal 2003, we adopted the 2003 Long-Term Incentive Plan (“LTIP”), 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, the LTIP is designed to motivate our executive officers to focus on long-term financial goals. The LTIP 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 outstanding 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.

The LTIP 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 award of phantom units is calculated by dividing a predetermined percentage (i.e., 52%), established upon adoption of the LTIP, 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 2009 award ended simultaneously with the conclusion of fiscal 2011. The TRU for the fiscal 2009 award fell within the second highest quartile. The following is a summary of the cash payouts related to the fiscal 2009 award earned by our named executive officers at the conclusion of fiscal 2011.


Michael J. Dunn, Jr.	$	350,057	⁽¹⁾
Michael A. Stivala	$	160,609	⁽¹⁾
Steven C. Boyd	$	160,609	⁽¹⁾
Mark Wienberg	$	123,962	⁽¹⁾
Douglas T. Brinkworth	$	139,008	⁽¹⁾


(1)		The cash payouts related to our named executive officers’ fiscal 2009 awards earned at the conclusion of fiscal 2011 is an additional disclosure that bears no meaningful relationship to the estimated probable outcomes 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 awards granted to our named executive officers during fiscal 2011 and fiscal 2010 that will be used to calculate cash payments at the end of each award’s respective three-year measurement period (i.e., at the end of fiscal 2013 for the fiscal 2011 award and at the end of fiscal 2012 for the fiscal 2010 award):


	Fiscal		Fiscal
	2011 Award		2010 Award
Michael J. Dunn, Jr.		4,787		5,981
Michael A. Stivala		2,217		2,597
Steven C. Boyd		2,177		2,550
Mark Wienberg		2,016		2,203
Douglas T. Brinkworth		1,975		2,314

The members of the peer groups selected by the Committee for the fiscal 2011, fiscal 2010 and fiscal 2009 awards consist entirely of publicly-traded partnerships. The Committee decided upon these peer groups because all publicly-traded partnerships have similar tax attributes and can, as a result, distribute more cash than similarly-sized corporations generating similar revenues. At its November 10, 2009 meeting, the Committee reviewed the performance of each of the members of the peer group used for the fiscal 2009 and fiscal 2008 LTIP awards and, as a result, replaced two of the members of the peer group for the fiscal 2011 and fiscal 2010 LTIP awards. Among other factors, in reaching its decision to replace two members of the current peer group, the Committee considered distributions and price fluctuations.

The following tables list, in alphabetical order, the names and ticker symbols of the peer group used to measure our performance during the fiscal 2011, fiscal 2010 and fiscal 2009 LTIP awards’ three-year measurement periods:

Fiscal 2011 and Fiscal 2010 LTIP Award Peer Group


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

Fiscal 2009 LTIP 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

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.

The grant date values based on the probable outcomes of the LTIP awards granted during the fiscal year are reported in the column titled “Unit Awards ($)” in the Summary Compensation Table below.

Restricted Unit Plans

2000 and 2009 Restricted Unit Plans (collectively referred to hereafter as the “RUP”)

We adopted the 2000 Restricted Unit Plan 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 this plan which, among other things, increased the number of Common Units authorized for issuance under this plan by 230,000 for a total of 717,805. As this plan terminated by its terms on October 31, 2010, no future awards can be made under this plan; however such termination will not affect the continued validity of any awards granted under the plan prior to its termination.

At our July 22, 2009 Tri-Annual Meeting, our Unitholders approved our adoption of the 2009 Restricted Unit Plan effective August 1, 2009. Upon adoption, this plan authorized the issuance of 1,200,000 Common Units to our executive officers, managers and other employees and to the members of our Board of Supervisors. The provisions of both restricted unit plans are substantially identical. At the conclusion of fiscal 2011, there remained 967,594 restricted units available under the RUP for future awards.

When the Committee authorizes an award of restricted units, the unvested units underlying an award do not provide the grantee with voting rights and do not receive distributions or accrue rights to distributions during the vesting period. Restricted unit awards normally 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 awards are subject to forfeiture in certain circumstances as defined in the applicable RUP document. Upon vesting, restricted units are automatically converted into our Common Units, with full voting rights and rights to receive distributions.

The RUP contains a retirement provision that provides for the vesting (six months and one day after the retirement date of qualifying participants) of unvested awards held by a retiring participant who meet all three of the following conditions on his or her retirement date:

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

	2.		The grantee is age 55 or older; and

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

All RUP awards are approved by the Committee. Because individual circumstances differ, the Committee has not adopted a formulaic approach to making RUP awards. Although the reasons for granting an award can vary, the objective of granting an award to a recipient is 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 grants RUP awards 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 grant to executive officers 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 award 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 outstanding unvested RUP awards held by our executive officers.

The Committee generally approves awards under the RUP at its first meeting each fiscal 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.

On October 31, 2007, the Committee adopted a general policy with respect to the effective grant date of subsequent awards 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 2011, RUP awards were granted to the following named executive officers:


Grant Name	Date	Quantity

Michael J. Dunn, Jr.	December 1, 2010		9,060
Michael A. Stivala	December 1, 2010		5,436
Steven C. Boyd	December 1, 2010		5,436
Mark Wienberg	December 1, 2010		5,436
Douglas T. Brinkworth	December 1, 2010		5,436

In connection with Mr. Dunn’s assumption of additional responsibilities as the Partnership’s Chief Executive Officer at the commencement of fiscal 2010, the Committee, at its November 10, 2009 meeting, granted Mr. Dunn a RUP award, as of December 1, 2010, equal in value to $500,000. The Committee made this award because it believes that equity compensation is a critical component of executive compensation that helps to retain and motivate our executives and because the Committee wished to mitigate a perceived shortfall between the cash components of Mr. Dunn’s compensation and the mean compensation for a comparable position reported in the Mercer database. This RUP award was converted into 9,060 restricted units on the grant date using the formula set forth above. The terms of Mr. Dunn’s award are such that the entire award will vest on the last day of fiscal 2012 and at no time between the grant date and this vesting date will this award be subject to the vesting upon retirement provisions of the RUP described above. In determining the fiscal 2011 awards for Mr. Stivala, Mr. Boyd, Mr. Wienberg and Mr. Brinkworth, the Committee relied upon information provided by the Mercer database to conclude that these awards were necessary to remediate shortfalls perceived by the Committee in the cash compensation of these named executive officers as well as in recognition of their individual achievements.

The aggregate grant date fair values of RUP awards made during the fiscal year computed in accordance with accounting principles generally accepted in the United States of America is reported in the column titled “Unit Awards ($)” in the Summary Compensation Table below.

Equity Holding Policy

Effective April 22, 2010, the Committee adopted an Equity Holding Policy which establishes guidelines for the level of Partnership equity holdings that members of the Board and our executives are expected to maintain. The Equity Holding Policy can be accessed through a link on the Partnership’s website at www.suburbanpropane.com under the “Investors” tab.

The Partnership’s equity holding requirements are as follows:


Position		Amount
Member of the Board of Supervisors		2 x Annual Fee
Chief Executive Officer		5 x Base Salary
President		5 x Base Salary
Chief Operating Officer		3 x Base Salary
Chief Financial Officer		3 x Base Salary
Executive Vice President		3 x Base Salary
Senior Vice President		2.5 x Base Salary
Vice President		1.5 x Base Salary
Assistant Vice President		1 x Base Salary
Managing Director		1 x Base Salary

As of the January 3, 2011 measurement date, all of our executive officers, including our named executive officers, were in compliance with the Partnership’s Equity Holding Policy.

Incentive Compensation Recoupment Policy

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 (i.e., payments/awards pursuant to the annual cash bonus plan, LTIP and RUP) 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 under the “Investors” tab.

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 and Mr. Wienberg, 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 2011, 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 the lesser of 6% of their base salary or $245,000, 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 2011, our budgeted 401(k) Plan EBITDA was $195.0 million. Based on actual fiscal 2011 401(k) Plan EBITDA results, each of our executive officers earned a matching contribution of 25%. As a result, we will provide participants with a match equal to 25% of their calendar year 2011 contributions that did not exceed 6% of their total base pay up to a maximum base pay of $245,000. The matching contributions that we will make on behalf of our named executive officers are reported in the column titled “All Other Compensation ($)” in the Summary Compensation Table below.

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 was to provide certain of our executive officers 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 the remaining participants.

At the conclusion of fiscal 2010, Mr. Dunn was the only remaining participant in the SERP. Due to the actuarial costs and administrative burdens associated with maintaining this plan for one participant, at its November 9, 2010 meeting, the Committee terminated the SERP and paid Mr. Dunn his accrued benefit of $57,611 on December 1, 2010. Because Mr. Dunn received no above-market interest credits relative to the SERP during fiscal years 2010 and 2009, nothing related to Mr. Dunn’s participation in 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, on the same basis as other exempt employees. These benefit plans are offered to attract and retain talented employees by providing them with competitive benefits.

Other than to Mr. Dunn, in accordance with the terms of his letter agreement (described below in the section titled “Letter Agreement of Mr. Dunn”), 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 2011.


			Employer-
	Tax Preparation		Provided
Name	Services		Vehicle		Physical
Michael J. Dunn, Jr.	$	7,700	$	16,302	$	1,300
Michael A. Stivala	$	-0-	$	14,698	$	-0-
Steven C. Boyd	$	7,200	$	7,221	$	-0-
Mark Wienberg	$	-0-	$	11,970	$	1,300
Douglas T. Brinkworth	$	5,100	$	10,851	$	1,300

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 implication of such changes to us.

Although it is the Partnership’s practice to comply with the statutory and regulatory provisions of IRC Section 409A, 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.

Letter Agreement of Mr. Dunn

Simultaneous with the commencement of fiscal 2010, Mr. Dunn’s then existing employment agreement was terminated by mutual agreement and replaced with a letter agreement governing retirement and the implementation of a mutually agreed upon succession plan. The letter agreement between Mr. Dunn and us is summarized as follows:

•

Mr. Dunn will participate in our Severance Protection Plan (see below) at the 78-week participation level.

•

If on or after the last day of fiscal 2012, Mr. Dunn retires or leaves as a result of an agreed-upon succession plan, he will receive the following:

•

A lump sum payment equal to two years of base salary.

•

Payment of medical benefits until attainment of age 65 (Mr. Dunn will be 63 at the conclusion of fiscal 2012).

•

Payment of unvested LTIP awards held by Mr. Dunn at separation in accordance with the terms and conditions of the LTIP plan document.

•

Transfer of ownership of employer-provided vehicle to Mr. Dunn.

•

Receipt of other vested and certain unvested benefits including his unvested RUP awards, his earned cash bonus and his vested pension plan balance in accordance with each plan’s terms and conditions.

In return for the foregoing, Mr. Dunn agreed to provide us with a release of all claims he might have against us at the time of his departure. Mr. Dunn also agreed to provide us with transition consultation services for a period not to exceed two years following his departure. Mr. Dunn will not be deemed to have retired or terminated his employment if he simply relinquishes the title and responsibilities of President but remains our Chief Executive Officer.

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”). During fiscal 2011, our Severance Protection Plan covered all executive officers, including the named executive officers.

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. 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 awards will vest immediately as if the three-year measurement period for each outstanding award 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, 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 Suburban, 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

•

The consummation of (a) a merger, consolidation or reorganization involving Suburban other than a Non-Control Transaction; (b) a complete liquidation or dissolution of Suburban; or (c) the sale or other disposition of 40% or more of the gross fair market value of all the assets of Suburban 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 2011.

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 2011

The following table sets forth certain information concerning the compensation of each named executive officer during the fiscal years ended September 24, 2011, September 25, 2010, and September 26, 2009:


											Change in
											Pension Value
											and
											Nonqualified
									Non-Equity		Deferred
							Unit		Incentive		Compensation		All Other
Name and Principal			Salary		Bonus		Awards		Plan Compen-		Earnings		Compensation		Total
Position	Year		($) ⁽¹⁾		($)		($) ⁽²⁾		sation ($) ⁽³⁾		($) ⁽⁴⁾		($) ⁽⁵⁾		($)
(a)	(b)		(c )		(d)		(e)		(g)		(h)		(i)		(j)
Michael J. Dunn, Jr.		2011	$	475,000		—	$	729,076	$	285,000	$	3,764	$	49,530	$	1,542,370
President and Chief		2010	$	475,000		—	$	768,484	$	475,000	$	31,661	$	49,330	$	1,799,475
Executive Officer		2009	$	433,333		—	$	314,197	$	467,500	$	56,050	$	48,065	$	1,319,145

Michael A. Stivala		2011	$	275,000		—	$	357,103	$	132,000		—	$	35,010	$	799,113
Chief Financial Officer		2010	$	275,000		—	$	320,699	$	206,250		—	$	37,569	$	839,518
		2009	$	262,500		—	$	231,333	$	214,500		—	$	41,728	$	750,061

Steven C. Boyd		2011	$	270,000		—	$	354,615	$	129,600	$	15,257	$	37,095	$	806,567
Vice President of		2010	$	270,000		—	$	317,799	$	202,500	$	21,101	$	34,762	$	846,162
Field Operations		2009	$	260,000		—	$	190,660	$	214,500	$	53,577	$	39,811	$	758,548

Mark Wienberg		2011	$	250,000		—	$	344,653	$	120,000		—	$	33,725	$	748,378
Vice President of		2010	$	250,000		—	$	273,398	$	175,000		—	$	35,755	$	734,153
Operational Support		2009	$	220,833		—	$	157,386	$	165,550		—	$	40,348	$	584,117
and Analysis

Douglas T. Brinkworth		2011	$	245,000		—	$	342,155	$	117,600	$	10,245	$	39,156	$	754,156
Vice President of		2010	$	245,000		—	$	303,237	$	183,750	$	12,959	$	41,767	$	786,713
Product Supply		2009	$	228,333		—	$	182,883	$	185,625	$	31,679	$	43,440	$	671,960


(1)		Includes amounts deferred by named executive officers as contributions to the qualified 401(k) Plan.

		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)		The amounts reported in this column represent the aggregate grant date fair value of RUP awards made during fiscal years 2011, 2010 and 2009, as well as the value at the grant date of LTIP awards made in fiscal years 2011, 2010, and 2009, based on the probable outcome with respect to satisfaction of the performance conditions. The specific details regarding these plans are provided in the preceding “Compensation Discussion and Analysis” under the subheadings “Restricted Unit Plans” and “2003 Long-Term Incentive Plan.” The breakdown for each plan with respect to each named executive officer is as follows:


Plan Name	Mr. Dunn		Mr. Stivala		Mr. Boyd		Mr. Wienberg		Mr. Brinkworth
2011
RUP	$	433,249	$	220,090	$	220,090	$	220,090	$	220,090
LTIP		295,827		137,013		134,525		124,563		122,065

Total	$	729,076	$	357,103	$	354,615	$	344.653	$	342,155


2010
RUP	$	399,438	$	160,456	$	160,456	$	160,456	$	160,456
LTIP		369,046		160,243		157,343		112,942		142,781

Total	$	768,484	$	320,699	$	317,799	$	273,398	$	303,237


2009
RUP	$	—	$	87,177	$	46,504	$	58,115	$	58,115
LTIP		314,197		144,156		144,156		99,271		124,768

Total	$	314,197	$	231,333	$	190,660	$	157,386	$	182,883


(3)		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.”

(4)		The amounts reported in this column represent each named executive officer’s Cash Balance Plan earnings and for Mr. Dunn, SERP earnings for fiscal years 2010 and 2009. The SERP was discontinued and the balance paid at the conclusion of fiscal 2010; therefore, there are no 2011 SERP earnings reported in the table. Neither Mr. Stivala nor Mr. Wienberg participates in the Cash Balance Plan.

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


2011
Type of Compensation	Mr. Dunn		Mr. Stivala		Mr. Boyd		Mr. Wienberg		Mr. Brinkworth
401(k) Match	$	3,675	$	3,675	$	3,675	$	3,675	$	3,675
Value of Annual Physical Examination		1,300		N/A		N/A		1,300		1,300
Value of Partnership Provided Vehicle		16,302		14,698		7,221		11,970		10,851
Tax Preparation Services		7,700		N/A		7,200		N/A		5,100
Cash Balance Plan Administrative Fees		1,500		N/A		1,500		N/A		1,500
Insurance Premiums		19,053		16,637		17,499		16,780		16,730

Totals	$	49,530	$	35,010	$	37,095	$	33,725	$	39,156


2010
Type of Compensation		Mr. Dunn	Mr. Stivala		Mr. Boyd		Mr. Wienberg		Mr. Brinkworth
401(k) Match	$	7,350	$	7,350	$	7,350	$	7,350	$	7,350
Value of Annual Physical Examination		1,300		1,300		N/A		1,300		1,300
Value of Partnership Provided Vehicle		13,868		12,903		6,251		10,993		11,966
Tax Preparation Services		6,500		N/A		3,600		N/A		3,600
Cash Balance Plan Administrative Fees		1,500		N/A		1,500		N/A		1,500
Insurance Premiums		18,812		16,016		16,061		16,112		16,051

Totals	$	49,330	$	37,569	$	34,762	$	35,755	$	41,767


2009
Type of Compensation	Mr. Dunn		Mr. Stivala		Mr. Boyd		Mr. Wienberg		Mr. Brinkworth
401(k) Match	$	14,700	$	14,700	$	14,700	$	13,748	$	13,825
Value of Annual Physical Examination		N/A		1,300		N/A		1,300		N/A
Value of Partnership Provided Vehicle		12,205		11,318		6,205		10,803		10,610
Tax Preparation Services		3,000		N/A		3,000		N/A		3,000
Cash Balance Plan Administrative Fees		1,500		N/A		1,500		N/A		1,500
Insurance Premiums		16,660		14,410		14,406		14,497		14,505

Totals	$	48,065	$	41,728	$	39,811	$	40,348	$	43,440


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

Grants of Plan Based Awards Table for Fiscal 2011

The following table sets forth certain information concerning grants of awards made to each named executive officer during the fiscal year ended September 24, 2011:

Phantom

Estimated Future

Units

Payments

All Other stock

Grant Date

Underlying

Under Non-Equity

Under Equity

Awards:

Fair Value of

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) ⁽⁴⁾

($)

(#)

($) ⁽⁵⁾

(a)

(b)

(d)

(e)

(g)

(h)

(i)

(l)

Michael J. Dunn, Jr.

RUP

⁽¹⁾

1 Dec 10

9 Nov 10

9,060

433,249

Bonus

⁽²⁾

26 Sep 10

475,000

570,000

LTIP

⁽³⁾

26 Sep 10

4,787

273,878

342,362

Michael A. Stivala

RUP

⁽¹⁾

1 Dec 10

9 Nov 10

5,436

220,090

Bonus

⁽²⁾

26 Sep 10

220,000

264,000

LTIP

⁽³⁾

26 Sep 10

2,217

126,842

158,538

Steven C. Boyd

RUP

⁽¹⁾

1 Dec 10

9 Nov 10

5,436

220,090

Bonus

⁽²⁾

26 Sep 10

216,000

259,200

LTIP

⁽³⁾

26 Sep 10

2,177

124,552

155,677

Mark Wienberg

RUP

⁽¹⁾

1 Dec 10

9 Nov 10

5,436

220,090

Bonus

⁽²⁾

26 Sep 10

200,000

240,000

LTIP

⁽³⁾

26 Sep 10

2,016

115,342

144,177

Douglas T. Brinkworth

RUP

⁽¹⁾

1 Dec 10

9 Nov 10

5,436

220,090

Bonus

⁽²⁾

26 Sep 10

196,000

235,200

LTIP

⁽³⁾

26 Sep 10

1,975

112,996

141,259


(1)		The quantities reported on these lines represent awards granted under the Partnership’s Restricted Unit Plans. Generally, 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 authority to alter the applicability of the plan’s retirement provisions in regard to a particular award. On September 24, 2011, Mr. Dunn was the only named executive officer who held RUP awards and, at the same time, satisfied all three retirement eligibility criteria. However, the terms of Mr. Dunn’s fiscal 2011 and fiscal 2010 awards are such that the entire awards will vest on the last day of fiscal 2012 and at no time between the grant date and the vesting date will these awards be subject to the normative retirement provisions of the 2000 or 2009 RUP documents. Detailed discussions of the general terms of the RUP and the facts and circumstances considered by the Committee in authorizing the fiscal 2011 awards to the named executive officers is included in the “Compensation Discussion and Analysis” under the subheading “Restricted Unit Plans.”

(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 2011 were equal to 60% 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 60% of the “Target” awards were earned by, our named executive officers during fiscal 2011, 60% of the “Target” amounts reported under column (d) have been reported in the Summary Compensation Table above.

(3)		The LTIP is a phantom unit plan. 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 2011 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 24, 2011) of our Common Units at the end of fiscal 2011, and (2) the estimated distributions over the course of the award’s three-year measurement period. Column (f) (“Threshold $”) was omitted because the LTIP does not provide for a minimum cash payment. The “Target ($)” amount represents a hypothetical payment at 100% of target and the “Maximum ($)” amount represents a hypothetical payment at 125% of target. 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 the LTIP during fiscal 2011.

(5)		The dollar amounts reported in this column represent the aggregate fair value of the RUP awards on the grant date, net of estimated future distributions during the vesting period. 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 2011 Table

The following table sets forth certain information concerning outstanding equity awards under our Restricted Unit Plans and phantom equity awards under our 2003 Long-Term Incentive Plan for each named executive officer as of September 24, 2011:


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	(#) ⁽⁶⁾		($) ⁽⁷⁾		(#) ⁽⁸⁾		($) ⁽⁹⁾
(a)	(g)		(h)		(i)		(j)
Michael J. Dunn, Jr.⁽¹⁾		42,557	$	1,965,069		10,768	$	615,698
Michael A. Stivala ⁽²⁾		19,813	$	914,865		4,814	$	275,263
Steven C. Boyd ⁽³⁾		18,417	$	850,405		4,727	$	270,287
Mark Wienberg ⁽⁴⁾		16,503	$	762,026		4,219	$	241,246
Douglas T. Brinkworth ⁽⁵⁾		17,134	$	791,162		4,289	$	245,244


(1)		Despite Mr. Dunn’s having met the plan’s retirement criteria (explained under the subheading “Restricted Unit Plans” in the “Compensation Discussion and Analysis”), the terms of Mr. Dunn’s fiscal 2011 and fiscal 2010 RUP awards of 9,060 and 11,348 unvested units, respectively, are such that the entire awards will vest on the last day of fiscal 2012 and at no time between the grant dates and the vesting date will these awards be subject to the normative retirement provisions of the 2000 or 2009 RUP documents. For more information on this and the retirement provisions, refer to the subheading “Restricted Unit Plans” in the “Compensation Discussion and Analysis.” If Mr. Dunn does not retire prior to the conclusion of the normal vesting schedule of his fiscal 2008 RUP award, his RUP awards will vest as follows:

Vesting

Dec 3,

Sep 29,

Dec 3,

Date

2011

2012

Quantity of Units

7,384

20,408

14,765


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

Dec 1,

Dec 3,

Apr 25,

Dec 1,

Dec 3,

Dec 1,

Vesting Date

2011

2012

2013

2014

2015

Quantity of Units

1,205

568

2,748

2,482

1,136

5,044

3,912

2,718


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

Dec 1,

Dec 3,

Apr 25,

Dec 1,

Dec 3,

Dec 1,

Vesting Date

2011

2012

2013

2014

2015

Quantity of Units

643

852

2,748

1,920

1,704

3,920

3,912

2,718


(4)		Mr. Wienberg’s RUP awards will vest as follows:

Dec 1,

Apr 25,

Dec 1,

Vesting Date

2011

2012

2013

2014

2015

Quantity of Units

803

2,748

2,080

4,292

3,962

2,618


(5)		Mr. Brinkworth’s RUP awards will vest as follows:

Dec 1,

Dec 3,

Apr 25,

Dec 1,

Dec 3,

Dec 1,

Vesting Date

2011

2012

2013

2014

2015

Quantity of Units

803

852

823

2,080

1,704

4,242

3,912

2,718


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

(7)		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 23, 2011, the last trading day of fiscal 2011.


(8)		The amounts reported in this column represent the quantities of phantom units that underlie the outstanding and unvested fiscal 2011 and fiscal 2010 awards under the LTIP. 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 the LTIP, refer to the subheading “2003 Long-Term Incentive Plan” in the “Compensation Discussion and Analysis.”

(9)		The amounts reported in this column represent the estimated future target payouts of the fiscal 2011 and fiscal 2010 LTIP-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 24, 2011 (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. Dunn		Mr. Stivala		Mr. Boyd		Mr. Wienberg		Mr. Brinkworth
Fiscal 2011 Phantom Units		4,787		2,217		2,177		2,016		1,975
Value of Fiscal 2011 Phantom Units	$	224,893	$	104,155	$	102,275	$	94,712	$	92,786
Estimated Distributions over Measurement Period	$	48,985	$	22,687	$	22,277	$	20,630	$	20,210

Fiscal 2010 Phantom Units		5,981		2,597		2,550		2,203		2,314
Value of Fiscal 2010 Phantom Units	$	280,987	$	122,007	$	119,799	$	103,497	$	108,712
Estimated Distributions over Measurement Period	$	60,833	$	26,414	$	25,936	$	22,407	$	23,536


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 2011

Awards under the Restricted Unit Plans 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 the vesting of awards under our Restricted Unit Plans and the vesting of the fiscal 2009 award under our 2003 Long-Term Incentive Plan for each named executive officer during the fiscal year ended September 24, 2011:


Restricted Unit Plans	Unit Awards
	Number of
	Common Units
	Acquired on		Value
	Vesting		Realized on
Name	(#)		Vesting ($) ⁽¹⁾
Michael J. Dunn, Jr.		7,384	$	410,883
Michael A. Stivala		4,280	$	239,616
Steven C. Boyd		5,426	$	299,272
Mark Wienberg		3,712	$	205,004
Douglas T. Brinkworth		4,853	$	268,877


(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 2009 ⁽²⁾ Award	Cash Awards
	Number of
	Phantom Units
	Acquired on		Value
	Vesting		Realized on
Name	(#) ⁽³⁾		Vesting ($) ⁽⁴⁾
Michael J. Dunn, Jr.		6,142	$	350,057
Michael A. Stivala		2,818	$	160,609
Steven C. Boyd		2,818	$	160,609
Mark Wienberg		2,175	$	123,962
Douglas T. Brinkworth		2,439	$	139,008


(2)		The fiscal 2009 award’s three-year measurement period concluded on September 24, 2011.

(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 the LTIP. For more information, refer to the subheading “2003 Long-Term Incentive Plan” in the “Compensation Discussion and Analysis.”

Pension Benefits Table for Fiscal 2011

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 24, 2011:


		Number		Present Value
		of Years		of		Payments
		Credited		Accumulated		During Last
		Service		Benefit		Fiscal Year
Name	Plan Name	(#)		($)		($)

Michael J. Dunn, Jr.	Cash Balance Plan⁽¹⁾		6	$	250,122	$	—
	LTIP ⁽³⁾		N/A	$	615,698	$	—
	RUP ⁽⁴⁾		N/A	$	1,022,730	$	—
	SERP ⁽⁵⁾		6	$	—	$	57,611

Michael A. Stivala ⁽²⁾	N/A		N/A	$	—	$	—

Steven C. Boyd	Cash Balance Plan ⁽¹⁾		15	$	156,680	$	—

Mark Wienberg ⁽²⁾	N/A		N/A	$	—	$	—

Douglas T. Brinkworth	Cash Balance Plan ⁽¹⁾		6	$	98,920	$	—


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

(2)		Because Mr. Stivala and Mr. Wienberg commenced employment with the Partnership after January 1, 2000, the date on which the Cash Balance Plan was closed to new participants, they do not participate in the Cash Balance Plan.

(3)		Currently, Mr. Dunn is the only named executive officer who meets the retirement criteria of the LTIP. For such participants, upon retirement, outstanding but unvested LTIP 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 outstanding fiscal 2011 and fiscal 2010 LTIP 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.

(4)		Currently, Mr. Dunn is the only named executive officer who meets the retirement criteria of the RUP. Despite Mr. Dunn’s having met the plan’s retirement criteria, only his fiscal 2008 award is currently subject to the plan’s retirement provisions until December 3, 2010. For more information on this and the retirement provisions, refer to the subheading “Restricted Unit Plans” in the “Compensation Discussion and Analysis.” For participants who meet the retirement criteria, upon retirement, outstanding RUP awards vest six months and one day after retirement.

(5)		At its November 9, 2010 meeting, the Committee terminated the SERP; on December 1, 2010, Mr. Dunn was paid his accrued benefit of $57,611.

Potential Payments Upon Termination

The following table sets forth certain information containing potential payments to the named executive officers in accordance with the provisions of the Severance Protection Plan, the RUP and the LTIP for the circumstances listed in the table assuming a September 24, 2011 termination date:


					Involuntary		Involuntary
					Termination		Termination
					Without Cause		Without Cause
					by the		by the
					Partnership or		Partnership or
					by the		by the
					Executive for		Executive for
					Good Reason		Good Reason
					without a		with a Change
					Change of		of Control
Executive Payments and Benefits Upon Termination	Death		Disability		Control Event		Event

Michael J. Dunn, Jr.
Cash Compensation ^{(1) (2) (3) (4)}	$	-0-	$	-0-	$	475,000	$	1,425,000
Accelerated Vesting of Fiscal 2011 and 2010 LTIP Awards ⁽⁵⁾		N/A		N/A		N/A		703,281
Accelerated Vesting of Outstanding RUP Awards ⁽⁶⁾		N/A		1,546,724		N/A		1,965,069
Medical Benefits ⁽³⁾		N/A		N/A		13,755		N/A
Total	$	-0-	$	1,546,724	$	488,755	$	4,093,350

Michael A. Stivala
Cash Compensation ^{(1) (2) (3) (4)}	$	-0-	$	-0-	$	275,000	$	742,500
Accelerated Vesting of Fiscal 2011 and 2010 LTIP Awards ⁽⁵⁾		N/A		N/A		N/A		314,091
Accelerated Vesting of Outstanding RUP Awards ⁽⁶⁾		N/A		663,858		N/A		914,865
Medical Benefits ⁽³⁾		N/A		N/A		13,755		N/A
Total	$	-0-	$	663,858	$	288,755	$	1,971,456

Steven C. Boyd
Cash Compensation ^{(1) (2) (3) (4)}	$	-0-	$	-0-	$	270,000	$	729,000
Accelerated Vesting of Fiscal 2011 and 2010 LTIP Awards ⁽⁵⁾		N/A		N/A		N/A		308,414
Accelerated Vesting of Outstanding RUP Awards ⁽⁶⁾		N/A		599,398		N/A		850,405
Medical Benefits ⁽³⁾		N/A		N/A		14,272		N/A
Total	$	-0-	$	599,398	$	284,272	$	1,887,819

Mark Wienberg
Cash Compensation ^{(1) (2) (3) (4)}	$	-0-	$	-0-	$	250,000	$	675,000
Accelerated Vesting of Fiscal 2011 and 2010 LTIP Awards ⁽⁵⁾		N/A		N/A		N/A		274,964
Accelerated Vesting of Outstanding RUP Awards ⁽⁶⁾		N/A		511,019		N/A		762,026
Medical Benefits ⁽³⁾		N/A		N/A		13,755		N/A
Total	$	-0-	$	511,019	$	263,755	$	1,711,990

Douglas T. Brinkworth
Cash Compensation ^{(1) (2) (3) (4)}	$	-0-	$	-0-	$	245,000	$	661,500
Accelerated Vesting of Fiscal 2011 and 2010 LTIP Awards ⁽⁵⁾		N/A		N/A		N/A		279,838
Accelerated Vesting of Outstanding RUP Awards ⁽⁶⁾		N/A		540,155		N/A		791,162
Medical Benefits ⁽³⁾		N/A		N/A		13,755		N/A
Total	$	-0-	$	540,155	$	258,755	$	1,732,500


(1)		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.

(2)		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.

(3)		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 and continued participation, at active employee rates, in the Partnership’s health insurance plans for one year.


(4)		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 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.”

(5)		In the event of a change of control, all LTIP awards will vest immediately regardless of whether termination immediately follows. If a change of control event occurs, the calculation of the LTIP 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 will be subject to the same risks as awards held by all other participants.

(6)		The RUP document makes no provisions for the vesting of awards held by recipients who die prior to the completion of the vesting schedule. If a recipient of a RUP award becomes permanently disabled, only those awards 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 will immediately vest; all awards held by the recipient for less than one year will be forfeited by the recipient. Because Mr. Dunn, Mr. Stivala, Mr. Boyd, Mr. Wienberg and Mr. Brinkworth each received a RUP award during fiscal 2011, if any or all of the five named executive officers had become permanently disabled on September 24, 2011, the following quantities of unvested restricted units would have vested: Dunn, 33,497: Stivala, 14,377; Boyd, 12,981; Wienberg, 11,067; Brinkworth, 11,698. The following quantities would have been forfeited: Dunn, 9,060; Stivala, 5,436; Boyd, 5,436; Wienberg, 5,436; Brinkworth, 5,436.

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

		In the event of a change of control, as defined in the RUP document, all unvested RUP awards will 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.

SUPERVISORS’ COMPENSATION

The following table sets forth the compensation of the non-employee members of the Board of Supervisors of the Partnership during fiscal 2011.


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

John D. Collins	$	75,000	$	0	$	75,000
Harold R. Logan, Jr.		100,000		0		100,000
Dudley C. Mecum		75,000		0		75,000
John Hoyt Stookey		75,000		0		75,000
Jane Swift		75,000		0		75,000


(1)		This includes amounts earned for fiscal 2011, including quarterly retainer installments for the fourth quarter of 2011 that were paid in November 2011. Does not include amounts paid in fiscal 2011 for fiscal 2010 quarterly retainer installments.

(2)		Our Supervisors did not receive RUP awards made during this fiscal year. All previous awards were made in accordance with the provisions of our Restricted Unit Plans and vest accordingly. As of September 24, 2011, each non-employee member of the Board of Supervisors held the following quantities of unvested restricted unit awards: Mr. Collins, 6,348 units; Mr. Logan, 5,100 units; Mr. Mecum, 5,100 units; Mr. Stookey, 5,100 units; and Ms. Swift, 6,348 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 non-employee 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.

Restricted Unit Plans. Each non-employee Supervisor participates in the Restricted Unit Plans. All awards vest in accordance with the provisions of the plan document (see “Compensation Discussion and Analysis” section titled “Restricted Unit Plans” for a description of the vesting schedule). Upon vesting, all awards are settled by issuing Common Units. During fiscal 2004, Messrs. Logan, Mecum and Stookey were granted unvested restricted unit plan awards of 8,500 units each; during fiscal 2007, each of them received an additional unvested award of 3,000 units. Upon commencement of their terms as supervisors in fiscal 2007, Mr. Collins and Ms. Swift each received an award of 5,496 units. During fiscal 2010, each non-employee Supervisor received a grant of 3,600 units. Messrs. Logan, Mecum and Stookey are the only non-employee Supervisors who have satisfied the retirement provisions of the Partnership’s Restricted Unit Plans.

Additional Supervisor Compensation. Non-employee Supervisors receive no other forms of remuneration from us. The only perquisite provided to the members of the Board of Supervisors is the ability to purchase propane at the same discounted rate that we offer propane to our employees, the value of which was less than $10,000 in fiscal 2011 for each Supervisor.


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

The following table sets forth certain information as of November 23, 2011 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 (1)		of Class
Michael J. Dunn, Jr. (a)		73,715		*
Michael A. Stivala (b)		11,784		*
Steven C. Boyd (c)		17,861		*
Mark Wienberg (d)		4,515		*
Douglas T. Brinkworth (e)		21,068		*

John Hoyt Stookey (f)		6,066		*
Harold R. Logan, Jr.(f)		16,730		*
Dudley C. Mecum (f)		15,634		*
John D. Collins (g)		15,198		*
Jane Swift (g)		1,374		*

All Members of the Board of Supervisors and Executive Officers, as a Group (16 persons) (h)		244,382		1	%


(1)		With the exception of the 784 units held by the General Partner (see (a) below), there is a possibility that any of the above listed units could be pledged as security.

*		Less than 1%.

(a)		Includes 784 Common Units held by the General Partner, of which Mr. Dunn is the sole member. Excludes 35,173 unvested restricted units, none of which will vest in the 60-day period following November 23, 2011.

(b)		Excludes 18,040 unvested restricted units, none of which will vest in the 60-day period following November 23, 2011.

(c)		Excludes 16,922 unvested restricted units, none of which will vest in the 60-day period following November 23, 2011.

(d)		Excludes 15,700 unvested restricted units, none of which will vest in the 60-day period following November 23, 2011.

(e)		Excludes 15,479 unvested restricted units, none of which will vest in the 60-day period following November 23, 2011.

(f)		Excludes 5,100 unvested restricted units, none of which will vest in the 60-day period following November 23, 2011.

(g)		Excludes 6,348 unvested restricted units, none of which will vest in the 60-day period following November 23, 2011.

(h)		Inclusive of the units referred to in footnotes (a), (b), (c), (d), (e), (f) and (g) above, the reported number of units excludes 207,501 unvested restricted units, none of which will vest in the 60 day period following November 23, 2011, owned by certain executive officers, whose restricted units vest on the same basis as described in footnotes (b), (c), (d), (e), (f) and (g) above.

Securities Authorized for Issuance Under the Restricted Unit Plans

The following table sets forth certain information, as of September 24, 2011, with respect to the Partnership’s Restricted Unit Plans, 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

future issuance under the

Units to be issued upon

Weighted-average grant

Restricted Unit Plans (excluding

vesting of restricted

date fair value per

securities reflected in

Plan

units

restricted unit

column (a))

Category

(a)

(b)

(c)

Equity compensation plans approved by security holders (1)

485,423

(2)

32.71

967,594

Equity compensation plans not approved by security holders

—

Total

485,423

32.71

967,594


(1)		Relates to the Restricted Unit Plans.

(2)		Represents number of restricted units that, as of September 24, 2011, had been granted under the 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;

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;

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

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 2011 and 2010 provided by PricewaterhouseCoopers LLP, our independent registered public accounting firm.


	Fiscal		Fiscal
	2011		2010

Audit Fees (a)	$	1,956,000	$	2,162,500
Tax Fees (b)		686,425		728,223
All Other Fees (c)		1,800		1,605


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

(c)		All Other Fees represent fees for the purchase of a license to an accounting research software tool.

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 2011 and fiscal 2010.

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.


	SUBURBAN PROPANE PARTNERS, L.P.
Date: November 23, 2011	By:	/s/ MICHAEL J. DUNN, JR.
		Michael J. Dunn, Jr.
		President, Chief Executive Officer and Supervisor

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/ MICHAEL J. DUNN, JR. (Michael J. Dunn, Jr.)	President, Chief Executive Officer and Supervisor	November 23, 2011

By:	/s/ HAROLD R. LOGAN, JR. (Harold R. Logan, Jr.)	Chairman and Supervisor	November 23, 2011

By:	/s/ JOHN HOYT STOOKEY (John Hoyt Stookey)	Supervisor	November 23, 2011

By:	/s/ DUDLEY C. MECUM (Dudley C. Mecum)	Supervisor	November 23, 2011

By:	/s/ JOHN D. COLLINS (John D. Collins)	Supervisor	November 23, 2011

By:	/s/ JANE SWIFT (Jane Swift)	Supervisor	November 23, 2011

By:	/s/ MICHAEL A. STIVALA (Michael A. Stivala)	Chief Financial Officer	November 23, 2011

By:	/s/ MICHAEL A. KUGLIN (Michael A. Kuglin)	Vice President and Chief Accounting Officer	November 23, 2011

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

	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, as amended as of June 24, 2009. (Incorporated by reference to Exhibit 10.2 to the Partnership’s Current Report on Form 8-K filed June 30, 2009).

	3.3	Amended and Restated Certificate of Limited Partnership of Suburban Propane Partners, L.P. dated May 26, 1999 (Incorporated by reference to Exhibit 3.2 to the Partnership’s Quarterly Report on Form 10-Q filed August 6, 2009).

	3.4	Amended and Restated Certificate of Limited Partnership of Suburban Partners, L.P. dated May 26, 1999 (Incorporated by reference to Exhibit 3.3 to the Partnership’s Quarterly Report on Form 10-Q filed August 6, 2009).

	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).

	4.4	Indenture, dated as of March 23, 2010, related to the 7.375% Senior Notes due 2020, by and among Suburban Propane Partners, L.P., Suburban Energy Finance Corporation and The Bank of New York Mellon, as Trustee, including the form of 7.375% Senior Notes due 2020. (Incorporated by reference to Exhibit 4.1 to the Partnership’s Current Report on Form 8-K filed March 23, 2010).

	4.5	First Supplemental Indenture, dated as of March 23, 2010, related to the 7.375% Senior Notes due 2020, by and among Suburban Propane Partners, L.P., Suburban Energy Finance Corporation and The Bank of New York Mellon, as Trustee. (Incorporated by reference to Exhibit 4.2 to the Partnership’s Current Report on Form 8-K filed March 23, 2010).

	10.1	Agreement between Michael J. Dunn, Jr. and the Partnership, effective as of September 27, 2009. (Incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed November 10, 2009).

	10.2	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, January 24, 2008, January 20, 2009 and November 10, 2009. (Incorporated by reference to Exhibit 10.6 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 26, 2009).

	10.3	Suburban Propane Partners, L.P. 2009 Restricted Unit Plan, effective August 1, 2009. (Incorporated by reference to Exhibit 99.1 to the Partnership’s Registration Statement on Form S-8 filed on July 24, 2009).

E-1


Exhibit
Number		Description

	10.4	Suburban Propane, L.P. Severance Protection Plan, as amended on January 24, 2008, January 20, 2009 and November 10, 2009. (Incorporated by reference to Exhibit 10.8 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 26, 2009).

	10.5	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, January 24, 2008 and January 20, 2009. (Incorporated by reference to Exhibit 10.3 to the Partnership’s Quarterly Report on Form 10-Q for the fiscal quarter ended December 27, 2008).

	10.6	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).

	10.7	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).

	10.8	Credit Agreement dated June 26, 2009. (Incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed on June 30, 2009).

	10.9	First Amendment to Credit Agreement, dated March 9, 2010, by and among Suburban Propane, L.P., Suburban Propane Partners, L.P., each lender signatory thereto and Bank of America, N.A., as the administrative agent for the lenders therein. (Incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed on March 9, 2010).

	10.10	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).

	10.11	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 President and Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. (Filed herewith).

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

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

	99.1	Equity Holding Policy for Supervisors and Executives of Suburban Propane Partners, L.P. (Incorporated by reference to Exhibit 99.1 to the Partnership’s Current Report on Form 8-K dated May 10, 2010).

E-2

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, of partners’ capital and of cash flows present fairly, in all material respects, the financial position of Suburban Propane Partners, L.P. and its subsidiaries at September 24, 2011 and September 25, 2010, and the results of their operations and their cash flows for each of the three years in the period ended September 24, 2011 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of September 24, 2011, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership’s management is responsible for these financial statements and financial statement schedule, 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, on the financial statement schedule, 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.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP
Florham Park, New Jersey
November 23, 2011

F-2

SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)


	September 24,			September 25,
	2011			2010

ASSETS
Current assets:
Cash and cash equivalents	$	149,553		$	156,908
Accounts receivable, less allowance for doubtful accounts of $6,960 and $5,403, respectively		66,630			60,383
Inventories		65,907			61,047
Other current assets		15,732			18,089

Total current assets		297,822			296,427
Property, plant and equipment, net		338,125			350,420
Goodwill		277,651			277,244
Other assets		42,861			46,823

Total assets	$	956,459		$	970,914


LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	37,456		$	39,886
Accrued employment and benefit costs		22,951			28,624
Accrued insurance		9,950			10,480
Customer deposits and advances		57,476			63,579
Other current liabilities		23,681			21,945

Total current liabilities		151,514			164,514
Long-term borrowings		348,169			347,953
Accrued insurance		42,891			44,965
Other liabilities		55,667			50,826

Total liabilities		598,241			608,258


Commitments and contingencies

Partners’ capital:
Common Unitholders (35,429 and 35,318 units issued and outstanding at September 24, 2011 and September 25, 2010, respectively)		418,134			419,882
Accumulated other comprehensive loss		(59,916	)		(57,226	)

Total partners’ capital		358,218			362,656

Total liabilities and partners’ capital	$	956,459		$	970,914

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 24,			September 25,			September 26,
	2011			2010			2009
Revenues
Propane	$	929,492		$	885,459		$	864,012
Fuel oil and refined fuels		139,572			135,059			159,596
Natural gas and electricity		84,721			77,587			76,832
All other		36,767			38,589			42,714

		1,190,552			1,136,694			1,143,154
Costs and expenses
Cost of products sold		678,719			598,451			540,385
Operating		279,329			289,567			304,767
General and administrative		51,648			61,656			57,044
Severance charge		2,000			—			—
Pension settlement charge		—			2,818			—
Depreciation and amortization		35,628			30,834			30,343

		1,047,324			983,326			932,539


Operating income		143,228			153,368			210,615
Loss on debt extinguishment		—			(9,473	)		(4,624	)
Interest income		16			61			802
Interest expense		(27,394	)		(27,458	)		(39,069	)


Income before provision for income taxes		115,850			116,498			167,724
Provision for income taxes		884			1,182			2,486


Net income	$	114,966		$	115,316		$	165,238


Income per Common Unit — basic	$	3.24		$	3.26		$	4.99

Weighted average number of Common Units outstanding — basic		35,525			35,374			33,134


Income per Common Unit — diluted	$	3.22		$	3.24		$	4.96

Weighted average number of Common Units outstanding — diluted		35,723			35,613			33,315

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 24,			September 25,			September 26,
	2011			2010			2009
Cash flows from operating activities:
Net income	$	114,966		$	115,316		$	165,238
Adjustments to reconcile net income to net cash provided by operations:
Depreciation and amortization expense		35,628			30,834			30,343
Pension settlement charge		—			2,818			—
Loss on debt extinguishment		—			9,473			4,624
Deferred tax provision		—			—			1,385
Other, net		3,316			6,120			3,895
Changes in assets and liabilities:
(Increase) decrease in accounts receivable		(6,247	)		(7,709	)		42,898
(Increase) decrease in inventories		(4,721	)		9,555			9,664
Increase (decrease) in accounts payable		(2,134	)		3,376			(22,402	)
Increase (decrease) in accrued employment and benefit costs		(5,673	)		(12,251	)		13,822
Increase (decrease) in accrued insurance		(2,604	)		3,127			(20,785	)
Increase (decrease) in customer deposits and advances		(6,103	)		(6,328	)		(5,437	)
(Increase) decrease in other current and noncurrent assets		2,470			1,479			19,121
Increase (decrease) in other current and noncurrent liabilities		3,888			(13	)		4,185

Net cash provided by operating activities		132,786			155,797			246,551

Cash flows from investing activities:
Capital expenditures		(22,284	)		(19,131	)		(21,837	)
Acquisitions of businesses		(3,195	)		(14,500	)		—
Proceeds from sale of property, plant and equipment		5,974			3,520			4,985

Net cash (used in) investing activities		(19,505	)		(30,111	)		(16,852	)

Cash flows from financing activities:
Repayments of long-term borrowings		—			(256,510	)		(177,821	)
Proceeds from long-term borrowings		—			247,840			100,000
Issuance costs associated with long-term borrowings		—			(5,018	)		(5,543	)
Repayments of short-term borrowings		—			—			(110,000	)
Net proceeds from issuance of Common Units		—			—			95,880
Partnership distributions		(120,636	)		(118,263	)		(106,740	)

Net cash (used in) financing activities		(120,636	)		(131,951	)		(204,224	)

Net (decrease) increase in cash and cash equivalents		(7,355	)		(6,265	)		25,475
Cash and cash equivalents at beginning of year		156,908			163,173			137,698

Cash and cash equivalents at end of year	$	149,553		$	156,908		$	163,173


Supplemental disclosure of cash flow information:
Cash paid for interest	$	24,584		$	28,362		$	39,153

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
						Other
	Number of					Compre-			Total
	Common		Common			hensive			Partners’			Comprehensive
	Units		Unitholders			(Loss) Income			Capital			Income (Loss)

Balance at September 27, 2008		32,725	$	262,050		$	(44,155	)	$	217,895

Net income				165,238						165,238		$	165,238
Other comprehensive income:
Net unrealized losses on cash flow hedges							(4,079	)		(4,079	)		(4,079	)
Reclassification of realized losses on cash flow hedges into earnings							3,088			3,088			3,088
Amortization of net actuarial losses and prior service credits into earnings and net change in funded status of benefit plans							(16,142	)		(16,142	)		(16,142	)

Total comprehensive income												$	148,105

Partnership distributions				(106,740	)					(106,740	)
Common Units issued under Restricted Unit Plans		72
Sale of Common Units under public offering, net of offering expenses		2,431		95,880						95,880
Compensation cost recognized under Restricted Unit Plans, net of forfeitures				2,396						2,396

Balance at September 26, 2009		35,228	$	418,824		$	(61,288	)	$	357,536

Net income				115,316						115,316		$	115,316
Other comprehensive income:
Net unrealized losses on cash flow hedges							(5,706	)		(5,706	)		(5,706	)
Reclassification of realized losses on cash flow hedges into earnings							3,597			3,597			3,597
Amortization of net actuarial losses and prior service credits into earnings and net change in funded status of benefit plans							3,353			3,353			3,353
Recognition in earnings of net actuarial loss for pension settlement							2,818			2,818			2,818

Total comprehensive income												$	119,378

Partnership distributions				(118,263	)					(118,263	)
Common Units issued under Restricted Unit Plans		90
Compensation cost recognized under Restricted Unit Plans, net of forfeitures				4,005						4,005

Balance at September 25, 2010		35,318	$	419,882		$	(57,226	)	$	362,656

Net income				114,966						114,966		$	114,966
Other comprehensive income:
Net unrealized losses on cash flow hedges							(1,177	)		(1,177	)		(1,177	)
Reclassification of realized losses on cash flow hedges into earnings							2,881			2,881			2,881
Amortization of net actuarial losses and prior service credits into earnings and net change in funded status of benefit plans							(4,394	)		(4,394	)		(4,394	)

Total comprehensive income												$	112,276

Partnership distributions				(120,636	)					(120,636	)
Common Units issued under Restricted Unit Plans		111
Compensation cost recognized under Restricted Unit Plans, net of forfeitures				3,922						3,922

Balance at September 24, 2011		35,429	$	418,134		$	(59,916	)	$	358,218

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 35,428,855 Common Units outstanding at September 24, 2011. 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, the sole member of which is the Partnership’s Chief Executive Officer. Other than as a holder of 784 Common Units that will remain in the General Partner, the General Partner does not have any economic interest in the Partnership or the Operating Partnership.

The Partnership’s fuel oil and refined fuels, natural gas and electricity and services businesses are structured as corporate entities (collectively referred to as the “Corporate Entities”) and, as such, are subject to corporate level income tax.

The Partnership serves approximately 750,000 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 2011, 2010 or 2009.

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. 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.

F-7

Fiscal Period. The Partnership uses a 52/53 week fiscal year which ends on the last Saturday in September. The Partnership’s fiscal quarters are generally 13 weeks in duration. When the Partnership’s fiscal year is 53 weeks long, the corresponding fourth quarter is 14 weeks in duration.

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 for amounts delivered, some of which may be unbilled at the end of each accounting period. Revenue from annually billed tank fees is deferred at the time of billings and recognized on a straight-line basis over one year.

Fair Value Measurements. The Partnership measures certain of its assets and liabilities at fair value, which is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants — in either the principal market or the most advantageous market. The principal market is the market with the greatest level of activity and volume for the asset or liability.

The common framework for measuring fair value utilizes a three-level hierarchy to prioritize the inputs used in the valuation techniques to derive fair values. The basis for fair value measurements for each level within the hierarchy is described below with Level 1 having the highest priority and Level 3 having the lowest.

•		Level 1: Quoted prices in active markets for identical assets or liabilities.

•		Level 2: Quoted prices in active markets for similar assets or liabilities; quoted prices for identical or similar instruments in markets that are not active; and model-derived valuations in which all significant inputs are observable in active markets.

•		Level 3: Valuations derived from valuation techniques in which one or more significant inputs are unobservable.

Business Combinations. At the beginning of fiscal 2010, the Partnership adopted revised accounting guidance concerning business combinations. The Partnership accounts for business combinations using the purchase method and accordingly, the assets and liabilities of the acquired entities are recorded at their estimated fair values at the acquisition date. Goodwill represents the excess of the purchase price over the fair value of the net assets acquired, including the amount assigned to identifiable intangible assets. The primary drivers that generate goodwill are the value of synergies between the acquired entities and the Partnership and the acquired assembled workforce, neither of which qualifies as an identifiable intangible asset. Identifiable intangible assets with finite lives are amortized over their useful lives. The results of operations of acquired businesses are included in the Consolidated Financial Statements from the acquisition date. The Partnership expenses all acquisition-related costs as incurred. Certain provisions of the revised guidance, in particular one related to the accounting for acquired tax benefits, are required to be applied regardless of when the business combination occurred. Therefore, to the extent the Partnership’s Corporate Entities generate taxable profits that enable the utilization of tax benefits acquired in prior business combinations, the corresponding reduction in the valuation allowance will be recorded as a reduction in the provision for income taxes. Previously, such valuation allowance reductions were recorded as a reduction to goodwill.

Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“US 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 material change in these estimates could occur in the near term.

F-8

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.

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 and, in certain instances, over-the-counter option contracts (collectively, “derivative instruments”) to hedge price risk associated with propane and fuel oil physical inventories, 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 at their fair values. 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 qualify for and are designated as normal purchase or normal sale contracts. Such contracts are exempted from the fair value accounting requirements 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, options and forward 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 (“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 earnings 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 are recognized in earnings 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, are recorded within earnings 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 borrowings bear interest at prevailing interest rates based upon, at the Operating Partnership’s option, LIBOR plus an applicable margin or the base rate, defined as the higher of the Federal Funds Rate plus ¹/2 of 1% or the agent bank’s prime rate, or LIBOR plus 1%, plus the applicable margin. The applicable margin is dependent on the level of the Partnership’s total leverage (the ratio of total debt to income before deducting interest expense, income taxes, depreciation and amortization (“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 swaps have been designated as, and are accounted for as, cash flow hedges. The fair value of the interest rate swaps are determined using an income approach, whereby future settlements under the swaps are converted into a single present value, with fair value being based on the value of current market expectations about those future amounts. Changes in the fair value are recognized in OCI until the hedged item is recognized in earnings. However, due to changes in the underlying interest rate environment, the corresponding value in OCI is subject to change prior to its impact on earnings.

F-9

Long-Lived Assets.

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		3-20 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 27 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 2021. Non-compete agreements are amortized under the straight-line method over the periods of the related agreements. 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.

F-10

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 related to the amount of the liability expected to be covered by insurance.

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.

Income Taxes. As discussed in Note 1, the Partnership structure consists of two limited partnerships, the Partnership and the Operating Partnership, and the 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 tax. 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.

Loss Contingencies. In the normal course of business, the Partnership is involved in various claims and legal proceedings. The Partnership records a liability for such matters when it is probable that a loss has been incurred and the amounts can be reasonably estimated. The liability includes probable and estimable legal costs to the point in the legal matter where the Partnership believes a conclusion to the matter will be reached. When only a range of possible loss can be established, the most probable amount in the range is accrued. If no amount within this range is a better estimate than any other amount within the range, the minimum amount in the range is accrued.

Asset Retirement Obligations. Asset retirement obligations 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. The Partnership has recognized asset retirement obligations for certain costs to remove and properly dispose of underground and aboveground fuel oil storage tanks and contractually mandated removal of leasehold improvements.

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 the asset retirement obligation, when it has a legal obligation 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.

F-11

Unit-Based Compensation. The Partnership recognizes 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. The Partnership measures 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.

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 commodity 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. Computations of basic income per Common Unit are performed by dividing net income by the weighted average number of outstanding Common Units, and vested (and unissued) restricted units granted under the Partnership’s Restricted Unit Plans, as defined below, to retirement-eligible grantees. Computations of diluted income per Common Unit are performed by dividing net income by the weighted average number of outstanding Common Units and unissued restricted units granted under the Restricted Unit Plans. In computing diluted net income per Common Unit, weighted average units outstanding used to compute basic net income per Common Unit were increased by 198,298, 238,589 and 180,789 units for fiscal 2011, 2010 and 2009, 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, amortization of net actuarial losses and prior service credits into earnings and changes in the funded status of pension and other postretirement benefit plans.

Reclassifications and Revisions. Certain prior period amounts have been reclassified to conform with the current period presentation. In addition, other assets were increased by $654 and other liabilities were increased by $2,835, with a corresponding decrease of $2,181 to common unitholders as of September 27, 2008 to record an asset and a liability that were not included in the consolidated balance sheet in prior years.

F-12

Recently Issued Accounting Pronouncements. In May 2011, the Financial Accounting Standards Board (“FASB”) issued an accounting standard update to provide guidance on achieving a consistent definition of and common requirements for fair value measurement and related disclosure requirements in US GAAP. The new guidance requires quantitative information about unobservable inputs, valuation processes and sensitivity analysis associated with fair value measurements categorized within Level 3 of the fair value hierarchy, and is effective prospectively during interim and annual periods beginning after December 15, 2011, which will be the second quarter of the Partnership’s 2012 fiscal year. Early adoption is not permitted. No material impact is expected on the Partnership’s consolidated financial position, results of operations and cash flows.

In June 2011, the FASB issued an accounting standard update to provide guidance on increasing the prominence of items reported in other comprehensive income. This update eliminates the option to present components of other comprehensive income as part of the statement of partners’ capital and requires that the total of comprehensive income, the components of net income and the components of other comprehensive income be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. Early adoption of this updated guidance is permitted, and it becomes effective retrospectively during interim and annual periods beginning after December 15, 2011, which will be the second quarter of the Partnership’s 2012 fiscal year. This update does not change the items that must be reported in other comprehensive income.

Subsequent Events. The Partnership has evaluated all subsequent events that occurred after the balance sheet date through the date its financial statements were issued, and concluded there were no events or transactions occurring during this period that required recognition or disclosure in its financial statements.

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.

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 24, 2011:


	Fiscal		Fiscal		Fiscal
	2011		2010		2009

First Quarter	$	0.8525	$	0.8350	$	0.8100
Second Quarter		0.8525		0.8400		0.8150
Third Quarter		0.8525		0.8450		0.8250
Fourth Quarter		0.8525		0.8500		0.8300

F-13

4. Selected Balance Sheet Information

Inventories consist of the following:


	As of
	September 24,		September 25,
	2011		2010

Propane, fuel oil and refined fuels and natural gas	$	64,601	$	59,836
Appliances and related parts		1,306		1,211

	$	65,907	$	61,047

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 24,		September 25,
	2011		2010

Land and improvements	$	27,904	$	28,250
Buildings and improvements		82,639		80,072
Transportation equipment		19,067		22,959
Storage facilities		79,525		78,176
Equipment, primarily tanks and cylinders		485,859		481,423
Computer systems		47,718		44,705
Construction in progress		2,704		5,290

		745,416		740,875
Less: accumulated depreciation		407,291		390,455

	$	338,125	$	350,420

Depreciation expense for the fiscal 2011, 2010 and 2009 amounted to $32,368, $28,411 and $28,123, respectively. During fiscal 2011 and fiscal 2010, the Partnership recorded a $2,883 and $1,800 adjustment, respectively, to accelerate depreciation expense on certain assets taken out of service.

5. Goodwill and Other Intangible Assets

The Partnership’s fiscal 2011 and fiscal 2010 annual goodwill impairment review resulted in no adjustments to the carrying amount of goodwill. During fiscal 2009, the Partnership reversed $1,385 of the deferred tax asset valuation allowance, respectively, which was established through purchase accounting, as a reduction to goodwill. This adjustment resulted from the utilization of a portion of the net operating losses established in purchase accounting. As a result of the adoption of revised accounting guidance concerning business combinations at the beginning of fiscal 2010, future reversals of the deferred tax asset valuation allowance will be reflected as a reduction of income tax expense.

F-14

The changes in carrying value of goodwill assigned to the Partnership’s operating segments are as follows:


			Fuel oil and			Natural gas
	Propane		refined fuels			and electricity		Total
Balance as of September 25, 2010
Goodwill	$	264,906	$	10,900		$	7,900	$	283,706
Accumulated adjustments		—		(6,462	)		—		(6,462	)

	$	264,906	$	4,438		$	7,900	$	277,244


Balance as of September 24, 2011
Goodwill	$	265,313	$	10,900		$	7,900	$	284,113
Accumulated adjustments		—		(6,462	)		—		(6,462	)

	$	265,313	$	4,438		$	7,900	$	277,651


Goodwill acquired during fiscal 2011	$	407	$	—		$	—	$	407

Other intangible assets consist of the following:


	As of
	September 24,			September 25,
	2011			2010

Customer lists	$	26,523		$	25,761
Non-compete agreements		3,756			3,156
Tradenames		1,499			1,499
Other		1,967			1,967

		33,745			32,383

Less: accumulated amortization
Customer lists		(15,036	)		(12,671	)
Non-compete agreements		(760	)		(107	)
Tradenames		(1,162	)		(1,012	)
Other		(709	)		(617	)

		(17,667	)		(14,407	)

	$	16,078		$	17,976

Aggregate amortization expense related to other intangible assets for fiscal 2011, 2010 and 2009 was $3,260, $2,423 and $2,220, respectively. Aggregate amortization expense for each of the five succeeding fiscal years related to other intangible assets held as of September 24, 2011 is as follows: 2012 — $2,834; 2013 — $2,676; 2014 — $2,341; 2015 — $2,180 and 2016 — $1,690.

6. 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. With the exception of those states that impose an entity-level income tax on partnerships, 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 each partner’s basis in the Partnership.

F-15

As described in Note 1 and Note 2, the earnings of the Corporate Entities are subject to corporate level federal and state income tax. However, based upon past performance, the Corporate Entities are currently reporting an income tax provision composed primarily of alternative minimum tax and state income taxes in the few states that impose taxes on partnerships. A full valuation allowance has been provided against the deferred tax assets 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 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 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 24,		September 25,		September 26,
	2011		2010		2009

Current
Federal	$	135	$	177	$	173
State and local		749		1,005		928

		884		1,182		1,101

Deferred		—		—		1,385

	$	884	$	1,182	$	2,486

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 24,			September 25,			September 26,
	2011			2010			2009

Income tax provision at federal statutory tax rate	$	40,548		$	40,361		$	58,704
Impact of Partnership income not subject to federal income taxes		(39,952	)		(38,808	)		(56,294	)
Permanent differences		239			2,051			719
Change in valuation allowance		(454	)		(4,806	)		(2,048	)
State income taxes		492			2,247			1,262
Other		11			137			143

Provision for income taxes — current and deferred	$	884		$	1,182		$	2,486

F-16

The components of net deferred taxes and the related valuation allowance using currently enacted tax rates are as follows:


	As of
	September 24,			September 25,
	2011			2010
Deferred tax assets:
Net operating loss carryforwards	$	32,938		$	33,214
Allowance for doubtful accounts		1,323			713
Inventory		658			1,423
Intangible assets		1,201			1,362
Deferred revenue		1,303			1,408
Derivative instruments		71			700
AMT credit carryforward		1,086			925
Other accruals		1,936			1,726

Total deferred tax assets		40,516			41,471

Deferred tax liabilities:
Property, plant and equipment		314			815

Total deferred tax liabilities		314			815

Net deferred tax assets		40,202			40,656
Valuation allowance		(40,202	)		(40,656	)

Net deferred tax assets	$	—		$	—

7. Long-Term Borrowings

Long-term borrowings consist of the following:


	As of
	September 24,		September 25,
	2011		2010
7.375% senior notes, due March 15, 2020, net of unamortized discount of $1,831 and $2,047, respectively	$	248,169	$	247,953
Revolving Credit Agreement, due June 25, 2013		100,000		100,000

	$	348,169	$	347,953

On March 23, 2010, the Partnership and its 100%-owned subsidiary, Suburban Energy Finance Corporation, completed a public offering of $250,000 in aggregate principal amount of 7.375% senior notes due March 15, 2020 (the “2020 Senior Notes”). The 2020 Senior Notes were issued at 99.136% of the principal amount. The net proceeds from the issuance, along with cash on hand, were used to repurchase the 6.875% senior notes due in 2013 (the “2013 Senior Notes”) on March 23, 2010 through a redemption and tender offer. In connection with the repurchase of the 2013 Senior Notes, the Partnership recognized a loss on the extinguishment of debt of $9,473 in fiscal 2010, consisting of $7,231 for the repurchase premium and related fees, as well as the write-off of $2,242 in unamortized debt origination costs and unamortized discount.

The Partnership’s obligations under the 2020 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 2020 Senior Notes are structurally subordinated to, which means they rank effectively behind, any debt and other liabilities of the Operating Partnership. The 2020 Senior Notes mature on March 15, 2020 and require semi-annual interest payments in March and September. The Partnership is permitted to redeem some or all of the 2020 Senior Notes any time at redemption prices specified in the indenture governing the 2020 Senior Notes. In addition, the 2020 Senior Notes have a change of control provision that would require the Partnership to offer to repurchase the notes at 101% of the principal amount repurchased, if a change of control as defined in the indenture occurs and is followed by a rating decline (a decrease in the rating of the notes by either Moody’s Investors Service or Standard and Poor’s Rating Group by one or more gradations) within 90 days of the consummation of the change of control.

F-17

On June 26, 2009, the Operating Partnership executed a Credit Agreement (the “Credit Agreement”) to provide a four-year $250,000 revolving credit facility (the “Revolving Credit Facility”). The Credit Agreement replaced the Operating Partnership’s previous credit facility, which provided for a $108,000 term loan (the “Term Loan”) and a separate $175,000 working capital facility both of which, as amended, were scheduled to mature in March 2010. Borrowings under the Revolving Credit Facility may be used for general corporate purposes, including working capital, capital expenditures and acquisitions until maturity on June 25, 2013. The Operating Partnership has the right to prepay any borrowings under the Revolving Credit Facility, in whole or in part, without penalty at any time prior to maturity. At closing, the Operating Partnership borrowed $100,000 under the Revolving Credit Facility and, along with cash on hand, repaid the $108,000 then outstanding under the Term Loan and terminated the previous credit facility. In addition, the Partnership has standby letters of credit issued under the Revolving Credit Facility in the aggregate amount of $54,856 primarily in support of retention levels under its self-insurance programs, which expire periodically through April 15, 2012. Therefore, as of September 24, 2011 the Partnership had available borrowing capacity of $95,144 under the Revolving Credit Facility.

Borrowings under the Revolving Credit Facility bear interest at prevailing interest rates based upon, at the Operating Partnership’s option, LIBOR plus the applicable margin or the base rate, defined as the higher of the Federal Funds Rate plus ¹/2 of 1%, the agent bank’s prime rate, or LIBOR plus 1%, plus in each case the applicable margin. The applicable margin is dependent upon the Partnership’s ratio of total debt to EBITDA on a consolidated basis, as defined in the Revolving Credit Facility. As of September 24, 2011, the interest rate for the Revolving Credit Facility was approximately 3.25%. The interest rate and the applicable margin will be reset at the end of each calendar quarter.

The Partnership acts as a guarantor with respect to the obligations of the Operating Partnership under the Credit Agreement pursuant to the terms and conditions set forth therein. The obligations under the Credit Agreement are secured by liens on substantially all of the personal property of the Partnership, the Operating Partnership and their subsidiaries, as well as mortgages on certain real property.

On July 31, 2009, the Operating Partnership entered into an interest rate swap agreement with an effective date of March 31, 2010 and termination date of June 25, 2013. Under the interest rate swap agreement, the Operating Partnership will pay a fixed interest rate of 3.12% to the issuing lender on the notional principal amount outstanding, effectively fixing the LIBOR portion of the interest rate at 3.12%. In return, the issuing lender will pay to the Operating Partnership a floating rate, namely LIBOR, on the same notional principal amount. This interest rate swap agreement replaced the previous interest rate swap agreement which terminated on March 31, 2010. The interest rate swaps have been designated as a cash flow hedge.

The Revolving Credit Facility and the 2020 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. The Revolving Credit Facility contains certain financial covenants (a) requiring the Partnership’s consolidated interest coverage ratio, as defined, to be not less than 2.5 to 1.0 as of the end of any fiscal quarter; (b) prohibiting the total consolidated leverage ratio, as defined, of the Partnership from being greater than 4.5 to 1.0 as of the end of any fiscal quarter; and (c) prohibiting the Operating Partnership’s senior secured consolidated leverage ratio, as defined, from being greater than 3.0 to 1.0 as of the end of any fiscal quarter. Under the indenture governing the 2020 Senior Notes, 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. The Partnership and the Operating Partnership were in compliance with all covenants and terms of the 2020 Senior Notes and the Revolving Credit Facility as of September 24, 2011.

F-18

Debt origination costs representing the costs incurred in connection with the placement of, and the subsequent amendment to, long-term borrowings are capitalized within other assets and amortized on a straight-line basis over the term of the respective debt agreements. Other assets at September 24, 2011 and September 25, 2010 include debt origination costs with a net carrying amount of $7,207 and $9,157, respectively.

The aggregate amounts of long-term debt maturities subsequent to September 24, 2011 are as follows: 2012: $-0-; 2013: $100,000; 2014: $-0-; 2015: $-0-; and thereafter: $250,000.

8. Unit-Based Compensation Arrangements

As described in Note 2, the Partnership recognizes 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. The Partnership measures 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.

Restricted Unit Plans. In fiscal 2000 and fiscal 2009, the Partnership adopted the Suburban Propane Partners, L.P. 2000 Restricted Unit Plan and 2009 Restricted Unit Plan (collectively, the “Restricted Unit Plans”), respectively, which authorizes the issuance of Common Units to executives, managers and other employees and members of the Board of Supervisors of the Partnership. The total number of Common Units authorized for issuance under the Restricted Unit Plans was 1,906,971 as of September 24, 2011. Unless otherwise stipulated by the Compensation Committee of the Partnership’s Board of Supervisors on or before the grant date, Restricted Units issued under the Restricted Unit Plans 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 Restricted Unit Plans participants are not eligible to receive quarterly distributions on, or vote their respective restricted units until vested. Restricted units cannot be sold or transferred prior to vesting. The value of the restricted unit is established by the market price of the Common Unit on the date of grant, net of estimated future distributions during the vesting period. Restricted units are subject to forfeiture in certain circumstances as defined in the Restricted Unit Plans. Compensation expense for the unvested awards is recognized ratably over the vesting periods and is net of estimated forfeitures.

F-19

The following is a summary of activity in the Restricted Unit Plans:


				Weighted Average
				Grant Date Fair
	Units			Value Per Unit
Outstanding September 27, 2008		446,515		$	30.57
Granted		68,799			18.10
Forfeited		(28,382	)		(31.92	)
Vested		(71,637	)		(27.81	)

Outstanding September 26, 2009		415,295			28.89
Granted		160,771			32.11
Forfeited		(4,693	)		(30.31	)
Vested		(90,106	)		(30.37	)

Outstanding September 25, 2010		481,267			29.67
Granted		136,241			39.54
Forfeited		(21,290	)		(33.05	)
Vested		(110,795	)		(27.82	)

Outstanding September 24, 2011		485,423		$	32.71

As of September 24, 2011, unrecognized compensation cost related to unvested restricted units awarded under the Restricted Unit Plans amounted to $6,320. Compensation cost associated with the unvested awards is expected to be recognized over a weighted-average period of 1.8 years. Compensation expense for the Restricted Unit Plans for fiscal 2011, 2010 and 2009 was $3,922, $4,005 and $2,396, respectively.

Long-Term Incentive Plan. The Partnership has a non-qualified, unfunded long-term incentive plan for officers and key employees (the “LTIP”) 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 the LTIP 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 comprised of other publicly traded partnerships (master limited partnerships), as approved by the Compensation Committee of the Partnership’s 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 fiscal 2011, 2010 and 2009 was $1,504, $3,058 and $3,402, respectively. The cash payouts in fiscal 2011, 2010 and 2009, which related to the fiscal 2008, 2007 and 2006 awards, were $2,697, $2,741 and $2,720, respectively.

9. 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 $1,201, $2,504 and $5,676 for fiscal 2011, 2010 and 2009, respectively.

Defined Pension and Retiree Health and Life Benefits Arrangements

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.

F-20

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 2011, 2010 or 2009. During the last decade, cash balance plans came under increased scrutiny which resulted in litigation pertaining to the cash balance feature and the Internal Revenue Service (“IRS”) issued additional regulations governing these types of plans. In fiscal 2010, the IRS completed its review of the Partnership’s defined benefit pension plan and issued a favorable determination letter pertaining to the cash balance formula. However, 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.

The Partnership recognizes the funded status of pension and other postretirement benefit plans as an asset or liability on the balance sheet and recognizes changes in the funded status in comprehensive income (loss) in the year the changes occur. The Partnership uses the date of its consolidated financial statements as the measurement date of plan assets and obligations.

F-21

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 fiscal 2011 and 2010 and a statement of the funded status for both years. Under the Partnership’s cash balance defined benefit pension plan, the accumulated benefit obligation and the projected benefit obligation are the same.


							Retiree Health and Life
	Pension Benefits						Benefits
	2011			2010			2011			2010
Reconciliation of benefit obligations:
Benefit obligation at beginning of year	$	157,626		$	157,187		$	20,932		$	21,127
Service cost		—			—			7			7
Interest cost		6,822			7,503			855			1,013
Actuarial loss		9,165			9,059			631			285
Lump sum benefits paid		(6,365	)		(7,889	)		—			—
Ordinary benefits paid		(8,129	)		(8,234	)		(1,530	)		(1,500	)

Benefit obligation at end of year	$	159,119		$	157,626		$	20,895		$	20,932


Reconciliation of fair value of plan assets:
Fair value of plan assets at beginning of year	$	139,889		$	140,055		$	—		$	—
Actual return on plan assets		7,503			15,957			—			—
Employer contributions		—			—			1,530			1,500
Lump-sum benefits paid		(6,365	)		(7,889	)		—			—
Ordinary benefits paid		(8,129	)		(8,234	)		(1,530	)		(1,500	)

Fair value of plan assets at end of year	$	132,898		$	139,889		$	—		$	—


Funded status:
Funded status at end of year	$	(26,221	)	$	(17,737	)	$	(20,895	)	$	(20,932	)


Amounts recognized in consolidated balance sheets consist of:
Net amount recognized at end of year	$	(26,221	)	$	(17,737	)	$	(20,895	)	$	(20,932	)
Less: Current portion		—			—			1,669			1,620

Non-current benefit liability	$	(26,221	)	$	(17,737	)	$	(19,226	)	$	(19,312	)


Amounts not yet recognized in net periodic benefit cost and included in accumulated other comprehensive income (loss):
Actuarial net (loss) gain	$	(59,502	)	$	(56,267	)	$	1,825		$	2,492
Prior service credits		—			—			2,358			2,848

Net amount recognized in accumulated other comprehensive (loss) income	$	(59,502	)	$	(56,267	)	$	4,183		$	5,340

Amounts recognized in other comprehensive income consisted of net actuarial losses of $7,957 and $1,181 for pension benefits for fiscal 2011 and 2010, respectively. Amounts recognized in other comprehensive income consisted of net actuarial losses of $631 and $285 for other postretirement benefits for fiscal 2011 and 2010, respectively. The losses (gains) in accumulated other comprehensive loss as of September 24, 2011 that are expected to be recognized as components of net periodic benefit costs during fiscal 2012 are $5,271 and $(465) for pension and other postretirement benefits, respectively.

Plan Assets. 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. The Partnership employs a liability driven investment strategy, which seeks to increase the correlation of the plan’s assets and liabilities to reduce the volatility of the plan’s funded status. This strategy has resulted in an asset allocation that is largely comprised of investments in funds of fixed income securities. The target asset mix is as follows: (i) fixed income securities portion of the portfolio should range between 75% and 95%; and (ii) equity securities portion of the portfolio should range between 5% and 25%.

F-22

The following table presents the actual allocation of assets held in trust as of September 24, 2011 and September 25, 2010:


	2011			2010

Fixed income securities		88	%		86	%
Equity securities		12	%		14	%

		100	%		100	%

The fair values of the Partnership’s pension plan assets are measured using Level 2 inputs. The assets of the defined benefit pension plan have no significant concentration of risk and there are no restrictions on these investments.

The following table describes the measurement of the Partnership’s pension plan assets by asset category:


	As of September 24,		As of September 25,
	2011		2010
Short term investments (1)	$	1,439	$	1,259

Equity securities: (1) (2)
Domestic		10,823		13,042
International		5,342		6,563

Fixed income securities (1) (3)		115,294		119,025

	$	132,898	$	139,889


(1)		Includes funds which are not publicly traded and are valued at the net asset value of the units provided by the fund issuer.

(2)		Includes funds which invest primarily in a diversified portfolio of publicly traded US and Non-US common stock.

(3)		Includes funds which invest primarily in publicly traded and non-publicly traded, investment grade corporate bonds, U.S. government bonds and asset-backed securities.

Projected Contributions and Benefit Payments. There are no projected minimum funding requirements under the Partnership’s defined benefit pension plan for fiscal 2012. Estimated future benefit payments for both pension and retiree health and life benefits are as follows:


			Retiree
	Pension		Health and Life
Fiscal Year	Benefits		Benefits
2012	$	27,452	$	1,669
2013		13,804		1,603
2014		13,303		1,540
2015		12,494		1,466
2016		12,079		1,382
2017 through 2021		51,118		5,553

Estimated future pension benefit payments assumes that age 65 or older active and non-active eligible participants in the pension plan that had not received a benefit payment prior to fiscal 2012 will elect a benefit payment in fiscal 2012. In addition, for all periods presented, estimated future pension benefit payments assumes that participants will elect a lump sum payment in the fiscal year that the participant becomes eligible to receive benefits.

F-23

Effect on Operations. The following table provides the components of net periodic benefit costs included in operating expenses for fiscal 2011, 2010 and 2009:


	Pension Benefits									Retiree Health and Life Benefits
	2011			2010			2009			2011			2010			2009

Service cost	$	—		$	—		$	—		$	7		$	7		$	4
Interest cost		6,822			7,503			9,487			855			1,013			1,381
Expected return on plan assets		(6,295	)		(8,080	)		(9,205	)		—			—			—
Amortization of prior service credit		—			—			—			(490	)		(490	)		(490	)
Settlement charge		—			2,818			—			—			—			—
Recognized net actuarial loss		4,721			5,374			4,050			(35	)		(65	)		(312	)

Net periodic benefit costs	$	5,248		$	7,615		$	4,332		$	337		$	465		$	583

During fiscal 2010, lump sum pension settlement payments to either terminated or retired individuals amounted to $7,889, which exceeded the settlement threshold (combined service and interest costs of net periodic pension cost) of $7,503 for fiscal 2010, and as a result, the Partnership was required to recognize a non-cash settlement charge of $2,818 during fiscal 2010. The non-cash charge was required to accelerate recognition of a portion of cumulative unamortized losses in the defined benefit pension plan. During fiscal 2011 and 2009, the amount of the pension benefit obligation settled through lump sum payments did not exceed the settlement threshold; therefore, a settlement charge was not required to be recognized in either of those fiscal years.

Actuarial Assumptions. The assumptions used in the measurement of the Partnership’s benefit obligations as of September 24, 2011 and September 25, 2010 are shown in the following table:

Retiree Health and

Pension Benefits

Life Benefits

2011

2010

2011

2010

Weighted-average discount rate

4.375

4.750

4.000

4.250

Average rate of compensation increase

n/a

The assumptions used in the measurement of net periodic pension benefit and postretirement benefit costs for fiscal 2011, 2010 and 2009 are shown in the following table:


	Pension Benefits									Retiree Health and Life Benefits
	2011			2010			2009			2011			2010			2009

Weighted-average discount rate		4.750	%		5.125	%		7.625	%		4.250	%		5.000	%		7.625	%
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		5.000	%		6.250	%		7.390	%		n/a			n/a			n/a
Health care cost trend		n/a			n/a			n/a			7.950	%		8.150	%		9.000	%

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.

F-24

The 7.74% increase in health care costs assumed at September 24, 2011 is assumed to decrease gradually to 4.48% in fiscal 2028 and to remain at that level thereafter. An increase or decrease of the assumed health care cost trend rates by 1.0% in each year would have no material impact to the Partnership’s benefit obligation as of September 24, 2011 nor the aggregate of service and interest components of net periodic postretirement benefit expense for fiscal 2011. The Partnership has concluded that the prescription drug benefits within the retiree medical plan do not entitle the Partnership to an available Medicare subsidy.

10. Financial Instruments and Risk Management

Cash and Cash Equivalents. The fair value of cash and cash equivalents is not materially different from their carrying amount because of the short-term maturity of these instruments.

Derivative Instruments and Hedging Activities. The Partnership measures the fair value of its exchange-traded options and futures contracts using Level 1 inputs, the fair value of its interest rate swaps using Level 2 inputs and the fair value of its over-the-counter options contracts using Level 3 inputs. The Partnership’s over-the-counter options contracts are valued based on an internal option model. The inputs utilized in the model are based on publicly available information as well as broker quotes.

The following summarizes the fair value of the Partnership’s derivative instruments and their location in the consolidated balance sheet as of September 24, 2011 and September 25, 2010, respectively:


	As of September 24, 2011			As of September 25, 2010
Asset Derivatives	Location	Fair Value		Location	Fair Value
Derivatives not designated as hedging instruments:
Commodity options	Other current assets	$	3,710	Other current assets	$	2,601
	Other assets		612	Other assets		—

Commodity futures	Other current assets		1,132	Other current assets		22

		$	5,454		$	2,623


Liability Derivatives	Location	Fair Value		Location	Fair Value
Derivatives designated as hedging instruments:
Interest rate swaps	Other current liabilities	$	2,662	Other current liabilities	$	2,740
	Other liabilities		1,934	Other liabilities		3,561

		$	4,596		$	6,301

Derivatives not designated as hedging instruments:
Commodity options	Other current liabilities	$	2,407	Other current liabilities	$	641
	Other liabilities		69	Other liabilities		—

Commodity futures	Other current liabilities		—	Other current liabilities		1,838

		$	2,476		$	2,479

F-25

The following summarizes the reconciliation of the beginning and ending balances of assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs:


	Fair Value Measurement Using Significant
	Unobservable Inputs (Level 3)
	Fiscal 2011						Fiscal 2010
	Assets			Liabilities			Assets			Liabilities
Beginning balance of over-the-counter options	$	1,509		$	30		$	1,675		$	844
Beginning balance realized during the period		(1,509	)		(30	)		(1,434	)		(844	)
Change in the fair value of beginning balance		—			—			(241	)		—
Contracts purchased during the period		1,780			118			1,509			30

Ending balance of over-the-counter options	$	1,780		$	118		$	1,509		$	30

As of September 24, 2011, the Partnership’s outstanding commodity-related derivatives were scheduled to mature during the following 15 months, and have a weighted average maturity of approximately 4 months. As of September 25, 2010, the Partnership’s outstanding commodity-related derivatives were scheduled to mature during fiscal 2011, and had a weighted average maturity of approximately 3 months.

The effect of the Partnership’s derivative instruments on the consolidated statement of operations for fiscal 2011, 2010 and 2009 are as follows:


	Amount of Gains			Gains (Losses) Reclassified from
	(Losses) Recognized in			Accumulated OCI into Income
	OCI			(Effective Portion)
Derivatives in Cash Flow Hedging Relationships:	(Effective Portion)			Location	Amount

Fiscal 2011
Interest rate swap	$	(1,177	)	Interest expense	$	(2,881	)


Fiscal 2010
Interest rate swap	$	(5,706	)	Interest expense	$	(3,597	)


Fiscal 2009
Interest rate swap	$	(4,079	)	Interest expense	$	(3,088	)


		Amount of
		Unrealized
	Location of Gains	Gains (Losses)
	(Losses) Recognized in	Recognized in
Derivatives Not Designated as Hedging Instruments:	Income	Income

Fiscal 2011
Options	Cost of products sold	$	(1,517	)
Futures	Cost of products sold		2,948

		$	1,431

Fiscal 2010
Options	Cost of products sold	$	(1,275	)
Futures	Cost of products sold		(4,125	)

		$	(5,400	)

Fiscal 2009
Options	Cost of products sold	$	(589	)
Futures	Cost of products sold		2,302

		$	1,713

F-26

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 2011, 2010 or 2009 and no concentration of receivables exists as of September 24, 2011 or September 25, 2010. During fiscal 2011, 2010 and 2009, three suppliers provided approximately 37%, 38% and 40%, 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.

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 over- the-counter 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.

Bank Debt and Senior Notes. The fair value of the Revolving Credit Facility approximates the carrying value since the interest rates are adjusted quarterly to reflect market conditions. Based upon quoted market prices, the fair value of the Partnership’s 2020 Senior Notes was $248,500 as of September 24, 2011.

11. 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 $18,868, $17,561 and $17,254 for fiscal 2011, 2010 and 2009, respectively.

Future minimum rental commitments under noncancelable operating lease agreements as of September 24, 2011 are as follows:


	Minimum
	Lease
Fiscal Year	Payments
2012	$	15,836
2013		13,346
2014		11,540
2015		8,480
2016		4,993
2017 and thereafter		4,709

Contingencies.

Self Insurance. As described 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 24, 2011 and September 25, 2010, the Partnership had accrued liabilities of $52,841 and $55,445, respectively, representing the total estimated losses under these self-insurance programs. 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 $17,513 and $17,990 as of September 24, 2011 and September 25, 2010, respectively.

Legal Matters. As described in Note 2, the Partnership’s operations are subject to all operating hazards and risks normally incidental to handling, storing and delivering combustible liquids such as propane. The Partnership has been, and will continue to be, a defendant in various legal proceedings and litigation arising in the ordinary course of business, both as a result of these operating hazards and risks, and as a result of other aspects of its business. In this regard, the Partnership currently is a defendant in putative suits in several states. The complaints allege a number of claims, including as to the Partnership’s pricing, fee disclosure and tank ownership, under various consumer statutes, the Uniform Commercial Code, common law and antitrust law. Based on the nature of the allegations under these suits, the Partnership believes that the suits are without merit and are the Partnership is contesting each of these suits vigorously. With respect to the pending putative suits, other than for legal defense fees and expenses based on the merits of the allegations, a liability for a loss contingency is not required.

F-27

12. 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 2018. 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 $9,686. The fair value of residual value guarantees for outstanding operating leases was de minimis as of September 24, 2011 and September 25, 2010.

13. Public Offerings

On August 10, 2009, the Partnership sold 2,200,000 Common Units in a public offering at a price of $41.50 per Common Unit realizing proceeds of $86,700, net of underwriting commissions and other offering expenses. On August 24, 2009, following the underwriters’ partial exercise of their over-allotment option, the Partnership sold an additional 230,934 Common Units at $41.50 per Common Unit, generating additional net proceeds of $9,180. The aggregate net proceeds of $95,880, along with cash on hand, were used to fund the purchase of $175,000 aggregate principal amount of 2003 Senior Notes pursuant to a cash tender offer.

14. Segment Information

The Partnership manages and evaluates its operations in five operating segments, three of which are reportable segments: Propane, Fuel Oil and Refined Fuels and Natural Gas and Electricity. 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 otherwise 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.

F-28

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 24,			September 25,			September 26,
	2011			2010			2009
Revenues:
Propane	$	929,492		$	885,459		$	864,012
Fuel oil and refined fuels		139,572			135,059			159,596
Natural gas and electricity		84,721			77,587			76,832
All other		36,767			38,589			42,714

Total revenues	$	1,190,552		$	1,136,694		$	1,143,154


Operating income:
Propane	$	203,567		$	230,717		$	268,969
Fuel oil and refined fuels		11,140			11,589			17,950
Natural gas and electricity		11,667			11,629			12,791
All other		(13,750	)		(17,995	)		(16,346	)
Corporate		(69,396	)		(82,572	)		(72,749	)

Total operating income		143,228			153,368			210,615

Reconciliation to net income:
Loss on debt extinguishment		—			9,473			4,624
Interest expense, net		27,378			27,397			38,267
Provision for income taxes		884			1,182			2,486

Net income	$	114,966		$	115,316		$	165,238


Depreciation and amortization:
Propane	$	19,525		$	17,505		$	15,951
Fuel oil and refined fuels		4,139			3,277			4,253
Natural gas and electricity		897			970			1,008
All other		111			261			436
Corporate		10,956			8,821			8,695

Total depreciation and amortization	$	35,628		$	30,834		$	30,343


	As of
	September 24,		September 25,
	2011		2010
Assets:
Propane	$	706,008	$	693,699
Fuel oil and refined fuels		44,973		57,681
Natural gas and electricity		18,675		21,552
All other		3,719		3,042
Corporate		183,084		194,940

Total assets	$	956,459	$	970,914

F-30


	Page
PART I

ITEM 1. BUSINESS		1

ITEM 1A. RISK FACTORS		10

ITEM 1B. UNRESOLVED STAFF COMMENTS		20

ITEM 2. PROPERTIES		20

ITEM 3. LEGAL PROCEEDINGS		21

ITEM 4. REMOVED AND RESERVED		21

PART II

ITEM 5. MARKET FOR THE REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF UNITS		22

ITEM 6. SELECTED FINANCIAL DATA		23

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		26

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		44

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA		47

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE		50

ITEM 9A. CONTROLS AND PROCEDURES		50

ITEM 9B. OTHER INFORMATION		51

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND PARTNERSHIP GOVERNANCE		51

ITEM 11. EXECUTIVE COMPENSATION		56

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS		79

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE		81

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES		82

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES		83

SIGNATURES		84

EX-21.1
EX-23.1
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

	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.


*		XBRL (Extensible Business Reporting Language) information is furnished and not filed or a part of a registration or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934 and otherwise is not subject to liability under these actions.


	Page

Report of Independent Registered Public Accounting Firm		F-2

Consolidated Balance Sheets — As of September 24, 2011 and September 25, 2010		F-3

Consolidated Statements of Operations — Years Ended September 24, 2011, September 25, 2010 and September 26, 2009		F-4

Consolidated Statements of Cash Flows — Years Ended September 24, 2011, September 25, 2010 and September 26, 2009		F-5

Consolidated Statements of Partners’ Capital — Years Ended September 24, 2011, September 25, 2010 and September 26, 2009		F-6

Notes to Consolidated Financial Statements		F-7


		Page
Schedule II	Valuation and Qualifying Accounts — Years Ended September 24, 2011, September 25, 2010 and September 26, 2009		S-2


	Balance at		Charged								Balance
	Beginning		(credited) to Costs			Other					at End
	of Period		and Expenses			Additions		Deductions (a)			of Period

Year Ended September 26, 2009

Allowance for doubtful accounts	$	6,578	$	3,284		$	—	$	(5,488	)	$	4,374
Valuation allowance for deferred tax assets		48,895		(2,048	)		—		(1,385	)		45,462

Year Ended September 25, 2010

Allowance for doubtful accounts	$	4,374	$	5,141		$	—	$	(4,112	)	$	5,403
Valuation allowance for deferred tax assets		45,462		(4,806	)		—		—			40,656

Year Ended September 24, 2011

Allowance for doubtful accounts	$	5,403	$	5,598		$	—	$	(4,041	)	$	6,960
Valuation allowance for deferred tax assets		40,656		(454	)		—		—			40,202