Suburban Propane Partners
Annual Report 2009

Plain-text annual report

Suburban Propane® 2 0 0 9 A N N U A L R E P O R T PARTNERSHIP PROFILE Suburban Propane Partners, L.P. (NYSE: SPH) has been in the customer service business since 1928. A Master Limited Partnership since 1996, Suburban is a value and growth-oriented company managed for long-term, consistent performance. Headquartered in Whippany, New Jersey, Suburban is a nationwide marketer and distributor of a diverse array of products to meet the energy needs of our customers, specializing in propane, fuel oil and refined fuels, as well as the marketing of natural gas and electricity in deregulated markets. With more than 2,900 employees, Suburban maintains business operations in 30 states, providing prompt, reliable service to approximately 850,000 residential, commercial, industrial and agricultural customers through more than 300 locations. During fiscal 2009, Suburban had retail propane sales of 343.9 million gallons which, based on industry statistics, constitutes about 4% of the total domestic retail market. In addition, Suburban had sales of fuel oil and other refined fuels of 57.4 million gallons in fiscal 2009. According to Department of Energy statistics, of the 111.1 million households in the United States, 12.6 million depend on propane for various uses and 8.4 million use fuel oil as their main heating fuel. Propane is a derivative of natural gas processing and petroleum refining. It is clean burning, abundant and available through an infrastructure of rail, barge, pipeline and truck transportation. Propane is stored in caverns, terminals and bulk storage plants before it is delivered to end users. Approximately 90% of the propane used in the United States is produced domestically. Fuel oil comes from domestic wells and refineries in addition to imports from foreign countries. Approximately 85% of the fuel oil consumed in the United States is refined domestically as part of the “distillate fuel oil” product family, which includes fuel oil and diesel fuel. Fuel oil is transported via barge, pipeline and truck transportation through terminals and bulk storage plants before being delivered to end users. SUBURBAN EXECUTIVE MANAGEMENT UNITHOLDER INFORMATION Executive Management Michael J. Dunn, Jr. President and Chief Executive Officer Michael A. Stivala Chief Financial Officer Michael M. Keating Senior Vice President — Administration A. Davin D'Ambrosio Vice President and Treasurer Paul Abel Vice President, General Counsel and Secretary Mark Anton II Vice President — Business Development Steven C. Boyd Vice President — Field Operations Douglas T. Brinkworth Vice President — Product Supply Neil E. Scanlon Vice President — Information Services Mark Wienberg Vice President — Operational Support and Analysis Exchange Listing Suburban Propane Partners, L.P. common units are listed on the New York Stock Exchange under the ticker symbol SPH. Transfer Agent/Unitholder Records Computershare Investor Services By Mail: Computershare Investor Services P.O. Box 43078 Providence, RI 02940-3078 United States of America By Overnight Delivery: Computershare Investor Services 250 Royall Street Canton, MA 02021 United States of America Michael A. Kuglin Controller and Chief Accounting Officer Telephone: +1 781-575-2724 Web Address: www.computershare.com Board of Supervisors Harold R. Logan, Jr.* Chairman John D. Collins* Dudley C. Mecum* John Hoyt Stookey* Jane Swift* Michael J. Dunn, Jr. * Member of both the Audit Committee and the Compensation Committee Investor Information Copies of Annual Reports, Interim Reports and other publications are available without charge from: Suburban Propane Partners, L.P. Investor Relations P.O. Box 206 Whippany, New Jersey 07981-0206 Telephone: 973-503-9252 Web Address: www.suburbanpropane.com Refer to our website for: • Company news, including the scheduling of analyst calls • Earnings releases • K-1’s It is anticipated that K-1’s will be available on our website and mailed to each Unitholder in late February 2010. UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K [X] Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the fiscal year ended September 26, 2009 [ ] 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 [X] No [ ] Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes [ ] No [X] Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). * Yes  No  * The registrant has not yet been phased into the interactive data requirements. Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See 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  Non-accelerated filer  (do not check if a smaller reporting company) Accelerated filer  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 [ ] No [X] The aggregate market value as of March 27, 2009 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 ($36.96 per unit), was approximately $1,212,166,000. Documents Incorporated by Reference: None Total number of pages (excluding Exhibits): 143 SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES INDEX TO ANNUAL REPORT ON FORM 10-K PART I Page ITEM 1. ITEM 1A. ITEM 1B. ITEM 2. ITEM 3. ITEM 4. BUSINESS...................................................................................................................... 1 RISK FACTORS............................................................................................................. 11 UNRESOLVED STAFF COMMENTS........................................................................... 21 PROPERTIES.................................................................................................................. 21 LEGAL PROCEEDINGS................................................................................................ 21 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.................... 22 PART II ITEM 5. ITEM 6. ITEM 7. ITEM 7A. ITEM 8. ITEM 9. ITEM 9A. ITEM 9B. MARKET FOR THE REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF UNITS......................... 23 SELECTED FINANCIAL DATA................................................................................... 24 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS....................................................... QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK..................................................................................…..................….. 48 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA...........................…. 51 CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE….......................................…...… 54 CONTROLS AND PROCEDURES................................................................................ 54 OTHER INFORMATION............................................................................................... 55 28 PART III ITEM 10. ITEM 11. ITEM 12. ITEM 13. ITEM 14. DIRECTORS, EXECUTIVE OFFICERS AND PARTNERSHIP GOVERNANCE...... 56 EXECUTIVE COMPENSATION............................................................…................... 61 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS........................ 97 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE.. .................................................................................... 99 PRINCIPAL ACCOUNTING FEES AND SERVICES.............................................…. 100 ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES............................................... 101 SIGNATURES............................................................…........................................................................... 102 PART IV DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS This Annual Report on Form 10-K contains forward-looking statements (“Forward-Looking Statements”) as defined in the Private Securities Litigation Reform Act of 1995 and Section 27A of the Securities Act of 1933, as amended, relating to future business expectations and predictions and financial condition and results of operations of Suburban Propane Partners, L.P. (the “Partnership”). Some of these statements can be identified by the use of forward-looking terminology such as “prospects,” “outlook,” “believes,” “estimates,” “intends,” “may,” “will,” “should,” “anticipates,” “expects” or “plans” or the negative or other variation of these or similar words, or by discussion of trends and conditions, strategies or risks and uncertainties. These Forward-Looking Statements involve certain risks and uncertainties that could cause actual results to differ materially from those discussed or implied in such Forward-Looking Statements (statements contained in this Annual Report identifying such risks and uncertainties are referred to as “Cautionary Statements”). The risks and uncertainties and their impact on the Partnership’s results include, but are not limited to, the following risks: • The impact of weather conditions on the demand for propane, fuel oil and other refined fuels, natural gas and electricity; • Volatility in the unit cost of propane, fuel oil and other refined fuels and natural gas, the impact of the Partnership’s hedging and risk management activities, and the adverse impact of price increases on volumes as a result of customer conservation; • The ability of the Partnership to compete with other suppliers of propane, fuel oil and other energy sources; • The impact on the price and supply of propane, fuel oil and other refined fuels from the political, military or economic instability of the oil producing nations, global terrorism and other general economic conditions; • The ability of the Partnership to acquire and maintain reliable transportation for its propane, fuel oil and other refined fuels; • The ability of the Partnership to retain customers; • The impact of customer conservation, energy efficiency and technology advances on the demand for propane and fuel oil; • The ability of management to continue to control expenses; • The impact of changes in applicable statutes and government regulations, or their interpretations, including those relating to the environment and global warming and other regulatory developments on the Partnership’s business; • The impact of 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 2009, that we are the fourth largest retail marketer of propane in the United States, measured by retail gallons sold in the year 2008. As of September 26, 2009, we were serving the energy needs of approximately 850,000 active residential, commercial, industrial and agricultural customers through approximately 300 locations in 30 states located primarily in the east and west coast regions of the United States, including Alaska. We sold approximately 343.9 million gallons of propane and 57.4 million gallons of fuel oil and refined fuels to retail customers during the year ended September 26, 2009. Together with our predecessor companies, we have been continuously engaged in the retail propane business since 1928. We conduct our business principally through Suburban Propane, L.P., a Delaware limited partnership, which operates our propane business and assets (the “Operating Partnership”), and its direct and indirect subsidiaries. Our general partner, and the general partner of our Operating Partnership, is Suburban Energy Services Group LLC (the “General Partner”), a Delaware limited liability company. Since October 19, 2006, the General Partner has had no economic interest in either the Partnership or the Operating Partnership other than as a holder of 784 Common Units of the Partnership. Prior to October 19, 2006, the General Partner was majority-owned by senior management of the Partnership and owned an approximate combined 1.75% general partner interest in the Partnership and the Operating Partnership. On October 19, 2006, the Partnership, the Operating Partnership and the General Partner consummated an Exchange Agreement by and among the parties dated July 27, 2006 (the “Exchange Agreement”), pursuant to which the Partnership issued 2,300,000 Common Units to the General Partner in exchange for the cancellation of the General Partner’s incentive distribution rights (“IDRs”), the economic interest in the Partnership included in the general partner interest therein and the economic interest in the Operating Partnership included in the general partner interest therein (the “GP Exchange Transaction”). Pursuant to a Distribution, Release and Lockup Agreement dated July 27, 2006 by and among the Partnership, the Operating Partnership, the General Partner and the then individual members of the General Partner (the “Distribution Agreement”), the Common Units received by the General Partner (other than 784 Common Units that will remain in the General Partner) were distributed to the then members of the General Partner in exchange for their interests in the General Partner. In addition to the GP Exchange Transaction, the Partnership adopted the Third Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”), which amended the previous partnership agreement to, among other things, effectuate the GP Exchange Transaction. Under the Partnership Agreement, the General Partner will continue to be the general partner of both the Partnership and the Operating Partnership, but its general partner interests will have no economic value (which means that such general partner interests do not entitle the holder thereof to any cash distributions of either partnership, or to any cash payment upon the liquidation of either partnership, or any other economic rights in either partnership). Following the GP Exchange Transaction and the consummation of the Distribution Agreement, the sole member of the General Partner is the Chief Executive Officer of the Partnership and the General Partner holds 784 Common Units received in the GP Exchange Transaction. The Partnership continues to own all of the limited partner interests in the Operating Partnership, with 0.1% thereof held through a limited liability company, wholly-owned (directly and indirectly) by the Partnership. Additionally, under the Partnership Agreement no IDRs are outstanding and no provisions 1 for future IDRs are contained in the Partnership Agreement. The Common Units represent 100% of the limited partner interests in the Partnership. Subsidiaries of the Operating Partnership include Suburban Sales and Service, Inc. (the “Service Company”), which conducts a portion of the Partnership’s service work and appliance and parts businesses. The Service Company is the sole member of Gas Connection, LLC (d/b/a HomeTown Hearth & Grill), and Suburban Franchising, LLC. HomeTown Hearth & Grill sells and installs natural gas and propane gas grills, fireplaces and related accessories and supplies through four retail stores in the northwest and northeast regions as of September 26, 2009. 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 corporate entities (collectively referred to as “Corporate Entities”) and, as such, are subject to corporate level income tax. Suburban Energy Finance Corporation, a direct wholly-owned subsidiary of the Partnership, was formed on November 26, 2003 to serve as co-issuer, jointly and severally with the Partnership, of the Partnership’s unsecured 6.875% senior notes due December 2013. Suburban Energy Finance Corporation has nominal assets and conducts no business operations. In this Annual Report, unless otherwise indicated, the terms “Partnership,” “we,” “us,” and “our” are used to refer to Suburban Propane Partners, L.P. and its consolidated subsidiaries, including the Operating Partnership. The Partnership, the Operating Partnership and the Service Company commenced operations in March 1996 in connection with the Partnership’s initial public offering of Common Units. We currently file Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and current reports on Form 8-K with the SEC. You may read and receive copies of any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Any information filed by us is also available on the SEC’s EDGAR database at www.sec.gov. Upon written request or through a link from our website at www.suburbanpropane.com, we will provide, without charge, copies of our Annual Report on Form 10-K for the year ended September 26, 2009, each of the Quarterly Reports on Form 10-Q, current reports filed or furnished on Form 8-K and all amendments to such reports as soon as is reasonably practicable after such reports are electronically filed with or furnished to the SEC. Requests should be directed to: Suburban Propane Partners, L.P., Investor Relations, P.O. Box 206, Whippany, New Jersey 07981-0206. Our Strategy Our business strategy is to deliver increasing value to our Unitholders through initiatives, both internal and external, that are geared toward achieving sustainable profitable growth and increased quarterly distributions. The following are key elements of our strategy: Internal Focus on Driving Operating Efficiencies, Right-Sizing Our Cost Structure and Enhancing Our Customer Mix. We focus internally on improving the efficiency of our existing operations, managing our cost structure and improving our customer mix. Through investments in our technology infrastructure, we continue to seek to improve operating efficiencies and the return on assets employed. Beginning at the end of fiscal 2005 and continuing throughout much of fiscal 2007, we implemented specific plans to streamline our operating footprint and management structure, eliminate redundant functions and assets through enhanced operating efficiencies, and refocus our service activities on offerings to support our existing customer base within our core operating segments. 2 While the majority of the specific initiatives under these plans were executed by the end of fiscal 2007, our focus on operating efficiencies and on our cost structure is an ongoing process. Our internal efforts are particularly focused in the areas of route optimization, forecasting customer usage, inventory control, cash management and customer tracking. In addition, we continually evaluate our customer base and, in particular, focus on customers that provide a proper return. In that regard, our efforts to strategically exit certain lower margin business in both our propane and fuel oil and refined fuels segments has resulted in a reduction in volumes sold, yet has had a favorable impact on overall segment profitability. Growing Our Customer Base by Improving Customer Retention and Acquiring New Customers. We set clear objectives to focus our employees on seeking new customers and retaining existing customers by providing world-class customer service. We believe that customer satisfaction is a critical factor in the growth and success of our operations. “Our Business is Customer Satisfaction” is one of our core operating philosophies. We measure and reward our customer service centers based on a combination of profitability of the individual customer service center and net customer growth. Selective Acquisitions of Complementary Businesses or Assets. Externally, we seek to extend our presence or diversify our product offerings through selective acquisitions. Our acquisition strategy is to focus on businesses with a relatively steady cash flow that will extend our presence in strategically attractive markets, complement our existing business segments or provide an opportunity to diversify our operations with other energy-related assets. While we are active in this area, we are also very patient and deliberate in evaluating acquisition candidates. There were no acquisitions completed during fiscal 2009, 2008 or 2007 as we focused internally on driving efficiencies and reducing costs. However, during fiscal 2007 we completed a non-cash transaction in which we disposed of nine customer service centers considered to be in markets that were non-strategic to our operations in exchange for three customer service centers located in Alaska, thus expanding our presence in this strategically attractive market. Selective Disposition of Non-Strategic Assets. We continuously evaluate our existing facilities to identify opportunities to optimize our return on assets by selectively divesting operations in slower growing markets, generating proceeds that can be reinvested in markets that present greater opportunities for growth. Our objective is to fully exploit the growth and profit potential of all of our assets. In that regard, in fiscal 2008 we completed the sale of our Tirzah, South Carolina underground granite propane storage cavern, and associated 62-mile pipeline, for approximately $53.7 million in net proceeds which have been reinvested in the business. Business Segments We manage and evaluate our operations in 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 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: Propane • • • residential and commercial applications; industrial applications; and agricultural uses. 3 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 26, 2009. Our operations are concentrated in the east and west coast regions of the United States, including Alaska. As of September 26, 2009, we serviced approximately 702,000 active propane customers. Typically, our customer service centers are located in suburban and rural areas where natural gas is not readily available. Generally, these customer service centers consist of an office, appliance showroom, warehouse and service facilities, with one or more 18,000 to 30,000 gallon storage tanks on the premises. Most of our residential customers receive their propane supply through an automatic delivery system that eliminates the customer’s need to make an affirmative purchase decision. These deliveries are scheduled through computer technology, based upon each customer’s historical consumption patterns and prevailing weather conditions. Additionally, as is common practice in the industry, we offer our customers a budget payment plan whereby the customer’s estimated annual propane purchases and service contracts are paid for in a series of estimated equal monthly payments over a twelve-month period. From our customer service centers, we also sell, install and service equipment to customers who purchase propane from us including heating and cooking appliances, hearth products and supplies and, at some locations, propane fuel systems for motor vehicles. We sell propane primarily to six customer markets: residential, commercial, industrial (including engine fuel), agricultural, other retail users and wholesale. Approximately 96% of the propane gallons sold by us in fiscal 2009 were to retail customers: 44% to residential customers, 31% to commercial customers, 8% to industrial customers, 6% to agricultural customers and 11% to other retail users. The balance of approximately 4% of the propane gallons sold by us in fiscal 2009 was for risk management activities and wholesale customers. Sales to residential customers in fiscal 2009 accounted for approximately 61% of our margins on retail propane sales, reflecting the higher-margin nature of the residential market. No single customer accounted for 10% or more of our propane revenues during fiscal 2009. Retail deliveries of propane are usually made to customers by means of bobtail and rack trucks. Propane is pumped from bobtail trucks, which have capacities ranging from 2,125 gallons to 2,975 gallons of propane, into a stationary storage tank on the customers’ premises. The capacity of these storage tanks ranges from approximately 100 gallons to approximately 1,200 gallons, with a typical tank having a capacity of 300 to 400 gallons. As is common in the propane industry, we own a significant portion of the storage tanks located on our customers’ premises. We also deliver propane to retail customers in portable cylinders, which typically have a capacity of 5 to 35 gallons. When these cylinders are delivered to customers, empty cylinders are refilled in place or transported for replenishment at our distribution locations. We also deliver propane to certain other bulk end users in larger trucks known as transports, which have an average capacity of approximately 9,000 gallons. End users receiving transport deliveries include industrial customers, large-scale heating accounts, such as local gas utilities that use propane as a supplemental fuel to meet peak load delivery requirements, and large agricultural accounts that use propane for crop drying. In our wholesale operations, we principally sell propane to large industrial end users and other propane distributors. The wholesale market includes customers who use propane to fire furnaces, as a cutting gas and in 4 other process applications. Due to the low margin nature of the wholesale market as compared to the retail market, we have reduced our emphasis on wholesale marketing over the last several years. Supply Our propane supply is purchased from approximately 52 oil companies and natural gas processors at approximately 125 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 2010. During fiscal 2009, Targa Liquids Marketing and Trade (“Targa”) and LDH Energy Mont Belvieu, L.P. (“LDH”) provided approximately 19% and 12% 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 LDH were interrupted, we would be able to secure adequate propane supplies from other sources without a material disruption of our operations. Nevertheless, the cost of acquiring such propane might be higher and, at least on a short-term basis, margins could be affected. Approximately 95% of our total propane purchases were from domestic suppliers in fiscal 2009. 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 (including our former facility in Tirzah, South Carolina). These storage facilities enable us to buy and store large quantities of propane particularly during periods of low demand, which generally occur during the summer months. This practice helps ensure a more secure supply of propane during periods of intense demand or price instability. As of September 26, 2009, the majority of our storage capacity in California was leased to third parties. Competition According to the U.S. Census Bureau, in a 2008 American Community Survey on house heating fuel, propane accounts for approximately 5% of household energy consumption in the United States. This level has not changed materially over the previous two decades. As an energy source, propane competes primarily with natural gas, electricity and fuel oil, principally on the basis of price, availability and portability. Propane is more expensive than natural gas on an equivalent British Thermal Unit basis in locations serviced by natural gas, but it is an alternative to natural gas in rural and suburban areas where natural gas is unavailable or portability of product is required. Historically, the expansion of natural gas into traditional propane markets has been inhibited by the capital costs required to expand pipeline and retail distribution systems. Although the recent extension of natural gas pipelines to previously unserved geographic areas tends to displace propane distribution in those areas, we believe new opportunities for propane sales have been arising as new neighborhoods are developed 5 in geographically remote areas. We also have some relative advantages over suppliers of other energy sources. For example, propane is generally less expensive to use than electricity for space heating, water heating, clothes drying and cooking. Fuel oil has not been a significant competitor due to the current geographical diversity of our operations, and propane and fuel oil are not significant competitors because of the cost of converting from one to the other. In addition to competing with suppliers of other energy sources, our propane operations compete with other retail propane distributors. The retail propane industry is highly fragmented and competition generally occurs on a local basis with other large full-service multi-state propane marketers, thousands of smaller local independent marketers and farm cooperatives. Based on industry statistics contained in 2007 Sales of Natural Gas Liquids and Liquefied Refinery Gases, as published by the American Petroleum Institute in December 2008, and LP/Gas Magazine dated February 2009, the ten largest retailers, including us, account for approximately 37% of the total retail sales of propane in the United States. For fiscal years 2009 and 2007, no single marketer had a greater than 10% share of the total retail propane market in the United States. For fiscal year 2008 one marketer had more than a 10% share of the total retail propane market in the United States. Most of our customer service centers compete with five or more marketers or distributors. However, each of our customer service centers operates in its own competitive environment because retail marketers tend to locate in close proximity to customers in order to lower the cost of providing service. Our typical customer service center has an effective marketing radius of approximately 50 miles, although in certain rural areas the marketing radius may be extended by a satellite office. Product Distribution and Marketing Fuel Oil and Refined Fuels We market and distribute fuel oil, kerosene, diesel fuel and gasoline to approximately 67,000 residential and commercial customers in the northeast region of the United States. Sales of fuel oil and refined fuels for fiscal 2009 amounted to 57.4 million gallons. Approximately 65% of the fuel oil and refined fuels gallons sold by us in fiscal 2009 were to residential customers, principally for home heating, 4% were to commercial customers, 1% were to agricultural and 4% to other users. Sales of diesel and gasoline accounted for the remaining 26% of total volumes sold in this segment during fiscal 2009. Fuel oil has a more limited use, compared to propane, for space and water heating in residential and commercial buildings. We sell diesel fuel and gasoline to commercial and industrial customers for use primarily to propel motor vehicles. Due to the low margin nature of the diesel fuel and gasoline businesses, at the end of fiscal 2005 we made a decision to reduce our emphasis on these activities and, in certain instances, exited the business. Approximately 54% of our fuel oil customers receive their fuel oil under an automatic delivery system without the customer having to make an affirmative purchase decision. These deliveries are scheduled through computer technology, based upon each customer’s historical consumption patterns and prevailing weather conditions. Additionally, as is common practice in the industry, we offer our customers a budget payment plan whereby the customer’s estimated annual fuel oil purchases and service contracts are paid for in a series of estimated equal monthly payments over a twelve-month period. From our customer service centers, we also sell, install and service equipment to customers who purchase fuel oil from us including heating appliances. Deliveries of fuel oil are usually made to customers by means of tankwagon trucks, which have capacities ranging from 2,500 gallons to 3,000 gallons. Fuel oil is pumped from the tankwagon truck into a stationary storage tank that is located on the customer’s premises, which is owned by the customer. The capacity of customer storage tanks ranges from approximately 275 gallons to approximately 1,000 gallons. No single customer accounted for 10% or more of our fuel oil revenues during fiscal 2009. 6 Supply We obtain fuel oil and other refined fuels in either pipeline, truckload or tankwagon quantities, and have contracts with certain pipeline and terminal operators for the right to temporarily store fuel oil at 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 2010. Competition The fuel oil industry is a mature industry with total demand expected to remain relatively flat to moderately declining. The fuel oil industry is highly fragmented, characterized by a large number of relatively small, independently owned and operated local distributors. We compete with other fuel oil distributors offering a broad range of services and prices, from full service distributors to those that solely offer the delivery service. We have developed a wide range of sales programs and service offerings for our fuel oil customer base in an attempt to be viewed as a full service energy provider and to build customer loyalty. For instance, like most companies in the fuel oil business, we provide home heating equipment repair service to our fuel oil customers through our services business on a 24-hour a day basis. The fuel oil business unit also competes for retail customers with suppliers of alternative energy sources, principally natural gas, propane and electricity. Natural Gas and Electricity We market natural gas and electricity through our wholly-owned subsidiary Agway Energy Services, LLC (“AES”) in the deregulated markets of New York and Pennsylvania primarily to residential and small commercial customers. Historically, local utility companies provided their customers with all three aspects of electric and natural gas service: generation, transmission and distribution. However, under deregulation, public utility commissions in several states are licensing energy service companies, such as AES, to act as alternative suppliers of the commodity to end consumers. In essence, we make arrangements for the supply of electricity or natural gas to specific delivery points. The local utility companies continue to distribute electricity and natural gas on their distribution systems. The business strategy of this business segment is to expand its market share by concentrating on growth in the customer base and expansion into other deregulated markets that are considered strategic markets. We serve nearly 76,000 natural gas and electricity customers in New York and Pennsylvania. During fiscal 2009, we sold approximately 3.6 million dekatherms of natural gas and 489.4 million kilowatt hours of electricity through the natural gas and electricity segment. Approximately 71% of our customers were residential households and the remainder was small commercial and industrial customers. New accounts are obtained through numerous marketing and advertising programs, including telemarketing and direct mail initiatives. Most local utility companies have established billing service arrangements whereby customers receive a single bill from the local utility company which includes distribution charges from the local utility company, as well as product charges for the amount of natural gas or electricity provided by AES and utilized by the customer. We have arrangements with several local utility companies that provide billing and collection services for a fee. Under these arrangements, we are paid by the local utility company for all or a portion of customer billings after a specified number of days following the customer billing with no further recourse to AES. 7 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 products. 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 heavily on propane, fuel oil or natural gas as a heating source. Accordingly, the volume sold is directly affected by the severity of the winter weather in our service areas, which can vary substantially from year to year. In any given area, sustained warmer than normal temperatures will tend to result in reduced propane, fuel oil and natural gas consumption, while sustained colder than normal temperatures will tend to result in greater consumption. Trademarks and Tradenames We utilize a variety of trademarks and tradenames owned by us, including “Suburban Propane,” “Gas Connection,” “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. 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. 8 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 26, 2009, we had accrued environmental liabilities of $1.7 million representing the total estimated future liability for remediation and monitoring. Estimating the extent of our responsibility at a particular site, and the method and ultimate cost of remediation of that site, requires making numerous assumptions. As a result, the ultimate cost to remediate any site may differ from current estimates, and will depend, in part, on whether there is additional contamination, not currently known to us, at that site. However, we believe that our past experience provides a reasonable basis for estimating these liabilities. As additional information becomes available, estimates are adjusted as necessary. While we do not anticipate that any such adjustment would be material to our financial statements, the result of ongoing or future environmental studies or other factors could alter this expectation and require recording additional liabilities. We currently cannot determine whether we will incur additional liabilities or the extent or amount of any such liabilities. National Fire Protection Association (“NFPA”) Pamphlet Nos. 54 and 58, which establish rules and procedures governing the safe handling of propane, or comparable regulations, have been adopted, in whole, in part or with state addenda, as the industry standard for propane storage, distribution and equipment installation and operation in all of the states in which we operate. In some states these laws are administered by state agencies, and in others they are administered on a municipal level. Pamphlet No. 58 has adopted storage tank valve retrofit requirements due to be completed by June 2011 or later depending on when each state adopts the 2001 edition of NFPA Pamphlet No. 58. We have a program in place to meet this deadline. NFPA Pamphlet Nos. 30, 30A, 31, 385 and 395, which establish rules and procedures governing the safe handling of distillates (fuel oil, kerosene and diesel fuel) and gasoline, or comparable regulations, have been adopted, in whole, in part or with state addenda, as the industry standard for fuel oil, kerosene, diesel fuel and gasoline storage, distribution and equipment installation/operation in all of the states in which we sell those 9 products. In some states these laws are administered by state agencies and in others they are administered on a municipal level. With respect to the transportation of propane, distillates and gasoline by truck, we are subject to regulations promulgated under the Federal Motor Carrier Safety Act. These regulations cover the transportation of hazardous materials and are administered by the United States Department of Transportation or similar state agencies. We conduct ongoing training programs to help ensure that our operations are in compliance with applicable safety regulations. We maintain various permits that are necessary to operate some of our facilities, some of which may be material to our operations. We believe that the procedures currently in effect at all of our facilities for the handling, storage and distribution of propane, distillates and gasoline are consistent with industry standards and are in compliance, in all material respects, with applicable laws and regulations. The Department of Homeland Security (“DHS”) has published regulations under 6 CFR Part 27 Chemical Facility Anti-Terrorism Standards. Our facilities are registered with the DHS – we have 468 facilities determined to be “Not a High Risk Chemical Facility” and 16 facilities determined to be Tier 4 (lowest level of security risk). Security Vulnerability Assessments for each of the 16 facilities have been submitted to DHS for review. 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. On June 26, 2009, the U.S. House of Representatives approved adoption of the “American Clean Energy and Security Act of 2009,” also known as the “Waxman-Markey cap-and-trade legislation” (“ACESA”). The purpose of ACESA is to control and reduce emissions of “greenhouse gases” (“GHGs”) in the United States. GHGs are certain gases, including carbon dioxide and methane, that may contribute to the warming of the Earth’s atmosphere and other climatic changes. ACESA would establish an economy-wide cap on emissions of GHGs in the United States and would require certain regulated entities to obtain GHG emission “allowances” corresponding to the annual emission of GHGs attributable to their products or operations. Regulated entities under ACESA include producers of natural gas liquids (“NGLs”), local natural gas distribution companies and certain industrial facilities. Under ACESA, the number of authorized emission allowances would decline each year, resulting in an expected and progressive increase in the cost or value of the allowances. The net effect of maintaining emission allowances under ACESA would be to increase the costs associated with the combusting of carbon-based fuels such as natural gas, NGLs (including propane), and refined petroleum products. The U.S. Senate has begun work on its own legislation for controlling and reducing domestic GHG emissions, and President Obama has indicated his support of legislation to reduce GHG emissions through an emission allowance system. Although it is not possible at this time to predict if or when the Senate may act on climate change legislation or how any Senate bill would be reconciled with ACESA, any adopted laws or regulations that restrict or reduce GHG emissions could require us to incur increased operating costs and could adversely affect demand for the products and services we provide. 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. Congress is currently considering legislation to impose restrictions on certain transactions involving derivatives, which could affect the use of derivatives in hedging transactions. ACESA contains provisions that would prohibit private energy commodity derivative and hedging transactions. ACESA would expand the power of the Commodity Futures Trading Commission (“CFTC”), to regulate derivative transactions related to energy 10 commodities, including oil and natural gas, and to mandate clearance of such derivative contracts through registered derivative clearing organizations. Under ACESA, the CFTC’s expanded authority over energy derivatives would terminate upon the adoption of general legislation covering derivative regulatory reform. The Chairman of the CFTC has announced that the CFTC intends to conduct hearings to determine whether to set limits on trading and positions in commodities with finite supply, particularly energy commodities, such as crude oil, natural gas and other energy products. The CFTC also is evaluating whether position limits should be applied consistently across all markets and participants. In addition, the Treasury Department recently has indicated that it intends to propose legislation to subject all OTC derivative dealers and all other major OTC derivative market participants to substantial supervision and regulation, including by imposing conservative capital and margin requirements and strong business conduct standards. Derivative contracts that are not cleared through central clearinghouses and exchanges may be subject to substantially higher capital and margin requirements. Although it is not possible at this time to predict whether or when Congress may act on derivatives legislation or how any climate change bill approved by the Senate would be reconciled with ACESA, any laws or regulations that may be adopted that subject us to additional capital or margin requirements relating to, or to additional restrictions on, our hedging and commodity positions could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activity. Employees As of September 26, 2009, we had 2,783 full time employees, of whom 493 were engaged in general and administrative activities (including fleet maintenance), 38 were engaged in transportation and product supply activities and 2,252 were customer service center employees. As of September 26, 2009, 61 of our employees were represented by 6 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 heavily on propane, fuel oil or natural gas as a heating source. The volume of propane, fuel oil and natural gas sold is at its highest during the six-month peak heating season of October through March and is directly affected by the severity of the winter. Typically, we sell approximately two-thirds of our retail propane volume and approximately three-fourths of our retail fuel oil volume during the peak heating season. Actual weather conditions can vary substantially from year to year, significantly affecting our financial performance. For example, average temperatures in our service territories were slightly warmer than normal for the year ended September 26, 2009 compared to 6% warmer than normal temperatures in both fiscal 2008 and fiscal 2007, 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 11 concentration of higher margin residential accounts and substantially all of our fuel oil and natural gas operations, generally have a greater impact on our operations than variations in the weather in other markets. We can give no assurance that the weather conditions in any quarter or year will not have a material adverse effect on our operations, or that our available cash will be sufficient to pay principal and interest on our indebtedness and distributions to unitholders. Sudden increases in the price of propane, fuel oil and other refined fuels and natural gas due to, among other things, our inability to obtain adequate supplies from our usual suppliers, may adversely affect our operating results. Our profitability in the retail propane, fuel oil and refined fuels and natural gas businesses is largely dependent on the difference between our product cost and retail sales price. Propane, fuel oil and other refined fuels and natural gas are commodities, and the unit price we pay is subject to volatile changes in response to changes in supply or other market conditions over which we have no control, including the severity of winter weather and the price and availability of competing alternative energy sources. In general, product supply contracts permit suppliers to charge posted prices at the time of delivery or the current prices established at major supply points, including Mont Belvieu, Texas, and Conway, Kansas. In addition, our supply from our usual sources may be interrupted due to reasons that are beyond our control. As a result, the cost of acquiring propane, fuel oil and other refined fuels and natural gas from other suppliers might be materially higher at least on a short- term basis. Since we may not be able to pass on to our customers immediately, or in full, all increases in our wholesale cost of propane, fuel oil and other refined fuels and natural gas, these increases could reduce our profitability. We engage in transactions to manage the price risk associated with certain of our product costs from time to time in an attempt to reduce cost volatility and to help ensure availability of product during periods of short supply. We can give no assurance that future volatility in propane, fuel oil and natural gas supply costs will not have a material adverse effect on our profitability and cash flow, or that our available cash will be sufficient to pay principal and interest on our indebtedness and distributions to our unitholders. Because of the highly competitive nature of the retail propane and fuel oil businesses, we may not be able to retain existing customers or acquire new customers, which could have an adverse impact on our operating results and financial condition. The retail propane and fuel oil industries are mature and highly competitive. We expect overall demand for propane to remain relatively constant over the next several years, while we expect the overall demand for fuel oil to be relatively flat to moderately declining during the same period. Year-to-year industry volumes of propane and fuel oil are expected to be primarily affected by weather patterns and from competition intensifying during warmer than normal winters, as well as from the impact of a sustained higher commodity price environment on customer conservation. Propane and fuel oil compete in the alternative energy sources market with electricity, natural gas and other existing and future sources of energy, some of which are, or may in the future be, less costly for equivalent energy value. For example, natural gas is a significantly less expensive source of energy than propane and fuel oil. As a result, except for some industrial and commercial applications, propane and fuel oil are generally not economically competitive with natural gas in areas where natural gas pipelines already exist. The gradual expansion of the nation’s natural gas distribution systems has made natural gas available in many areas that previously depended upon propane or fuel oil. Propane and fuel oil compete to a lesser extent with each other due to the cost of converting from one to the other. In addition to competing with other sources of energy, our propane and fuel oil businesses compete with other distributors principally on the basis of price, service, availability and portability. Competition in the retail propane business is highly fragmented and generally occurs on a local basis with other large full-service multi- state propane marketers, thousands of smaller local independent marketers and farm cooperatives. Our fuel oil business competes with fuel oil distributors offering a broad range of services and prices, from full service 12 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 believe our ability to compete effectively depends on reliability of service, responsiveness to customers and our ability to control expenses in order to maintain competitive prices. Energy efficiency, general economic conditions and technological advances have affected and may continue to affect demand for propane and fuel oil by our retail customers. The national trend toward increased conservation and technological advances, including installation of improved insulation and the development of more efficient furnaces and other heating devices, has adversely affected the demand for propane and fuel oil by our retail customers which, in turn, has resulted in lower sales volumes to our customers. In addition, recent economic conditions may lead to additional conservation by retail customers seeking to further reduce their heating costs, particularly during periods of sustained higher commodity prices as has been the case over the past three fiscal years. Future technological advances in heating, conservation and energy generation may adversely affect our financial condition and results of operations. Current conditions in the global capital and credit markets, and general economic pressures may adversely affect our financial position and results of operations. Our business and operating results are materially affected by worldwide economic conditions. Current conditions in the global capital and credit markets and general economic pressures have led to declining consumer and business confidence, increased market volatility and widespread reduction of business activity generally. As a result of this turmoil, coupled with increasing energy prices, our customers may experience cash flow shortages which may lead to delayed or cancelled plans to purchase our products, and affect the ability of our customers to pay for our products. In addition, disruptions in the U.S. residential mortgage market, increases in mortgage foreclosure rates and failures of lending institutions may adversely affect retail customer demand for our products (in particular, products used for home heating and home comfort equipment) and our business and results of operations. Our operating results and ability to generate sufficient cash flow to pay principal and interest on our indebtedness, and to pay distributions to unitholders, may be affected by our ability to continue to control expenses. The propane and fuel oil industries are mature and highly fragmented with competition from other multi- state marketers and thousands of smaller local independent marketers. Demand for propane and fuel oil is expected to be affected by many factors beyond our control, including, but not limited to, the severity of weather conditions during the peak heating season, customer conservation driven by high energy costs and other economic factors, as well as technological advances impacting energy efficiency. Accordingly, our propane and fuel oil sales volumes and related gross margins may be negatively affected by these factors beyond our control. Our operating profits and ability to generate sufficient cash flow may depend on our ability to continue to control expenses in line with sales volumes. We can give no assurance that we will be able to continue to control expenses to the extent necessary to reduce the effect on our profitability and cash flow from these factors. 13 The risk of terrorism and 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 and 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 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 range of federal, state and local laws and regulations related to environmental and health and safety matters including those concerning, among other things, the investigation and remediation of contaminated soil and groundwater and transportation of hazardous materials. These requirements are complex, changing and tend to become more stringent over time. In addition, we are required to maintain various permits that are necessary to operate our facilities, some of which are material to our operations. There can be no assurance that we have been, or will be, at all times in complete compliance with all legal, regulatory and permitting requirements or that we will not incur significant costs in the future relating to such requirements. Violations could result in penalties, or the curtailment or cessation of operations. Moreover, currently unknown environmental issues, such as the discovery of additional contamination, may result in significant additional expenditures, and potentially significant expenditures also could be required to comply with future changes to environmental laws and regulations or the interpretation or enforcement thereof. Such expenditures, if required, could have a material adverse effect on our business, financial condition or results of operations. We are subject to operating hazards and litigation risks that could adversely affect our operating results to the extent not covered by insurance. Our operations are subject to all operating hazards and risks normally associated with handling, storing and delivering combustible liquids such as propane, fuel oil and other refined fuels. As a result, we have been, and are likely to continue to be, a defendant in various legal proceedings and litigation arising in the ordinary course of business. We are self-insured for general and product, workers’ compensation and automobile liabilities up to predetermined amounts above which third-party insurance applies. We cannot guarantee that our insurance will be adequate to protect us from all material expenses related to potential future claims for personal injury and property damage or that these levels of insurance will be available at economical prices, or that all legal matters that arise will be covered by our insurance programs. 14  If we are unable to make acquisitions on economically acceptable terms or effectively integrate such acquisitions into our operations, our financial performance may be adversely affected. The retail propane and fuel oil industries are mature. We foresee only limited growth in total retail demand for propane and flat to moderately declining retail demand for fuel oil. With respect to our retail propane business, 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 by Congress could result in increased operating costs and reduced demand for the products and services we provide. On June 26, 2009, the U.S. House of Representatives approved adoption of the “American Clean Energy and Security Act of 2009,” also known as the “Waxman-Markey cap-and-trade legislation” (“ACESA”). The purpose of ACESA is to control and reduce emissions of “greenhouse gases” (“GHGs”) in the United States. GHGs are certain gases, including carbon dioxide and methane, that may contribute to the warming of the Earth’s atmosphere and other climatic changes. ACESA would establish an economy-wide cap on emissions of GHGs in the United States and would require certain regulated entities to obtain GHG emission “allowances” corresponding to the annual emission of GHGs attributable to their products or operations. Regulated entities under ACESA include producers of natural gas liquids (“NGLs”), local natural gas distribution companies, and certain industrial facilities. Under ACESA, the number of authorized emission allowances would decline each year, resulting in an expected and progressive increase in the cost or value of the allowances. The net effect of maintaining emission allowances under ACESA would be to increase the costs associated with the combusting of carbon-based fuels such as natural gas, NGLs (including propane), and refined petroleum products. The U.S. Senate has begun work on its own legislation for controlling and reducing domestic GHG emissions, and President Obama has indicated his support of legislation to reduce GHG emissions through an emission allowance system. Although it is not possible at this time to predict if or when the Senate may act on climate change legislation or how any Senate bill would be reconciled with ACESA, any adopted laws or regulations that restrict or reduce GHG emissions could require us to incur increased operating costs and could adversely affect demand for the products and services we provide. The adoption of derivatives legislation by Congress could have an adverse impact on our ability to hedge risks associated with our business. Congress is currently considering legislation to impose restrictions on certain transactions involving derivatives, which could affect the use of derivatives in hedging transactions. ACESA contains provisions that would prohibit private energy commodity derivative and hedging transactions. ACESA would expand the power of the Commodity Futures Trading Commission, (“CFTC”), to regulate derivative transactions related to energy commodities, including oil and natural gas, and to mandate clearance of such derivative contracts through registered derivative clearing organizations. Under ACESA, the CFTC’s expanded authority over energy derivatives would terminate upon the adoption of general legislation covering derivative regulatory reform. The Chairman of the CFTC has announced that the CFTC intends to conduct hearings to determine whether to set limits on trading and positions in commodities with finite supply, particularly energy commodities, such as crude oil, natural gas and other energy products. The CFTC also is evaluating whether position limits should be applied consistently across all markets and participants. In addition, the Treasury Department recently has indicated that it intends to propose legislation to subject all OTC derivative dealers and all other major OTC derivative market participants to substantial supervision and regulation, including by imposing conservative capital and margin 15 requirements and strong business conduct standards. Derivative contracts that are not cleared through central clearinghouses and exchanges may be subject to substantially higher capital and margin requirements. Although it is not possible at this time to predict whether or when Congress may act on derivatives legislation or how any climate change bill approved by the Senate would be reconciled with ACESA, any laws or regulations that may be adopted that subject us to additional capital or margin requirements relating to, or to additional restrictions on, our hedging and commodity positions could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activity. Risks Inherent in the Ownership of Our Common Units Cash distributions are not guaranteed and may fluctuate with our performance and other external factors. Cash distributions on our common units are not guaranteed, and depend primarily on our cash flow and our cash on hand. Because they are not dependent on profitability, which is affected by non-cash items, our cash distributions might be made during periods when we record losses and might not be made during periods when we record profits. The amount of cash we generate may fluctuate based on our performance and other factors, including: • • • the impact of the risks inherent in our business operations, as described above; required principal and interest payments on our debt and restrictions contained in our debt instruments; issuances of debt and equity securities; • our ability to control expenses; • • • fluctuations in working capital; capital expenditures; and financial, business and other factors, a number which will be beyond our control. Our Third Amended and Restated Agreement of Limited Partnership, as amended (“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 26, 2009, we had total outstanding borrowings of $350.0 million, including $250.0 million of senior notes issued by the Partnership and our wholly-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 makes to its unitholders is limited by the senior notes, and the amount of distributions that the Operating Partnership may make to the Partnership is limited by the revolving credit facility. 16 The revolving credit facility and the senior notes both contain various restrictive and affirmative covenants applicable to us and the Operating Partnership, respectively, including (a) restrictions on the incurrence of additional indebtedness, and (b) 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: (i) 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; (ii) 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 (iii) 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 26, 2009. The amount and terms of our debt may also adversely affect our ability to finance future operations and capital needs, limit our ability to pursue acquisitions and other business opportunities and make our results of operations more susceptible to adverse economic and industry conditions. In addition to our outstanding indebtedness, we may in the future require additional debt to finance acquisitions or for general business purposes; however, credit market conditions may impact our ability to access such financing. If we are unable to access needed financing or to generate sufficient cash from operations, we may be required to abandon certain projects or curtail capital expenditures. Additional debt, where it is available, could result in an increase in our leverage. Our ability to make principal and interest payments depends on our future performance, which is subject to many factors, some of which are beyond our control. Unitholders have limited voting rights. A Board of Supervisors manages our operations. Our unitholders have only limited voting rights on matters affecting our business, including the right to elect the members of our Board of Supervisors every three years. It may be difficult for a third party to acquire us, even if doing so would be beneficial to our unitholders. Some provisions of our Partnership Agreement may discourage, delay or prevent third parties from acquiring us, even if doing so would be beneficial to our unitholders. For example, our Partnership Agreement contains a provision, based on Section 203 of the Delaware General Corporation Law, that generally prohibits the Partnership from engaging in a business combination with a 15% or greater unitholder for a period of three years following the date that person or entity acquired at least 15% of our outstanding common units, unless certain exceptions apply. Additionally, our Partnership Agreement sets forth advance notice procedures for a unitholder to nominate a Supervisor to stand for election, which procedures may discourage or deter a potential 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: • a court or government agency determined that we were conducting business in the state but had not 17 complied with the state’s limited partnership statute; or • unitholders’ rights to act together to remove or replace the General Partner or take other actions under our Partnership Agreement are deemed to constitute “participation in the control” of our business for purposes of the state’s limited partnership statute. Unitholders may have liability to repay distributions. Unitholders will not be liable for assessments in addition to their initial capital investment in the common units. Under specific circumstances, however, unitholders may have to repay to us amounts wrongfully returned or distributed to them. Under Delaware law, we may not make a distribution to unitholders if the distribution causes our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and nonrecourse liabilities are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that a limited partner who receives a distribution of this kind and knew at the time of the distribution that the distribution violated Delaware law will be liable to the limited partnership for the distribution amount for three years from the distribution date. Under Delaware law, an assignee who becomes a substituted limited partner of a limited partnership is liable for the obligations of the assignor to make contributions to the partnership. However, such an assignee is not obligated for liabilities unknown to him at the time he or she became a limited partner if the liabilities could not be determined from the partnership agreement. If we issue additional limited partner interests or other equity securities as consideration for acquisitions or for other purposes, the relative voting strength of each unitholder will be diminished over time due to the dilution of each unitholder’s interests and additional taxable income may be allocated to each unitholder. Our Partnership Agreement generally allows us to issue additional limited partner interests and other equity securities without the approval of our unitholders. Therefore, when we issue additional common units or securities ranking on a parity with the common units, each unitholder’s proportionate partnership interest will decrease, and the amount of cash distributed on each common unit and the market price of common units could decrease. The issuance of additional common units will also diminish the relative voting strength of each previously outstanding common unit. In addition, the issuance of additional common units will, over time, result in the allocation of additional taxable income, representing built-in gains at the time of the new issuance, to those 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. 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 18 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. 19 The tax gain or loss on the disposition of common units could be different than expected. A unitholder who sells common units will recognize a gain or loss equal to the difference between the amount realized, including its share of our nonrecourse liabilities, and its adjusted tax basis in the common units. Prior distributions in excess of cumulative net taxable income allocated to a common unit which decreased a unitholder’s tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder’s tax basis in that common unit, even if the price is less than the original cost of the common unit. A portion of the amount realized, if the amount realized exceeds the unitholder’s adjusted basis in that common unit, will likely be characterized as ordinary income. Furthermore, should the IRS successfully contest some conventions used by us, a unitholder could recognize more gain on the sale of common units than would be the case under those conventions, without the benefit of decreased income in prior years. Reporting of partnership tax information is complicated and subject to audits. We furnish each unitholder with a Schedule K-1 that sets forth its allocable share of income, gains, losses and deductions. In preparing these schedules, we use various accounting and reporting conventions and adopt various depreciation and amortization methods. We cannot guarantee that these conventions will yield a result that conforms to statutory or regulatory requirements or to administrative pronouncements of the IRS. Further, our income tax return may be audited, which could result in an audit of a unitholder’s income tax return and increased liabilities for taxes because of adjustments resulting from the audit. We treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units. Because we cannot match transferors and transferees of common units and because of other reasons, uniformity of the economic and tax characteristics of the common units to a purchaser of common units of the same class must be maintained. To maintain uniformity and for other reasons, we have adopted certain depreciation and amortization conventions which may be inconsistent with Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to a unitholder. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units, and could have a negative impact on the value of our common units or result in audit adjustments to a unitholder’s income tax return. We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular 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 units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular 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. 20  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 26, 2009, we owned approximately 75% 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 26, 2009, we had a fleet of 8 transport truck tractors, of which we owned two, and 23 railroad tank cars, of which we owned none. In addition, as of September 26, 2009 we had 773 bobtail and rack trucks, of which we owned approximately 40%, 112 fuel oil tankwagons, of which we owned approximately 39%, and 1,051 other delivery and service vehicles, of which we owned approximately 49%. We lease the vehicles we do not own. As of September 26, 2009, we also owned approximately 717,751 customer propane storage tanks with typical capacities of 100 to 500 gallons, 150,839 customer propane storage tanks with typical capacities of over 500 gallons and 257,479 portable propane cylinders with typical capacities of five to ten gallons. ITEM 3. LEGAL PROCEEDINGS Litigation Our operations are subject to all operating hazards and risks normally incidental to handling, storing and delivering combustible liquids such as propane. As a result, we have been, and will continue to be, a defendant in various legal proceedings and litigation arising in the ordinary course of business. We are self-insured for general 21 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 $52.2 million at September 26, 2009), we do not believe that these pending or threatened litigation matters, or known claims or known contingent claims, will have a material adverse effect on our results of operations, financial condition or cash flow. For the portion of our estimated self-insurance liability that exceeds our deductibles, we record a corresponding asset related to the amount of the liability covered by insurance (which was approximately $14.8 million at September 26, 2009). ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS The 2009 Tri-Annual Meeting of the Partnership’s Unitholders (the “Tri-Annual Meeting”) was held on July 22, 2009. At the Tri-Annual Meeting, the Unitholders re-elected to the Board of Supervisors, for a three-year term, all six nominees proposed by the Board: Nominee Harold R. Logan, Jr. John Hoyt Stookey Dudley C. Mecum John D. Collins Jane Swift Michael J. Dunn, Jr. For 30,441,054 30,301,633 30,320,031 30,166,800 30,378,578 30,415,930 Withheld 838,790 978,211 959,813 1,113,044 901,266 863,914 At the Tri-Annual Meeting, the Unitholders also approved the following proposals: Adoption of the Partnership’s 2009 Restricted Unit Plan, including the authorization of 1,200,000 Common Units to be available for grant under the plan: For 15,829,007 Against 2,251,830 Abstain 578,168 Broker Non-Votes 12,620,839 Adjournment of the Tri-Annual Meeting, if necessary, to solicit additional proxies: For 28,923,408 Against 1,726,994 Abstain 626,942 Broker Non-Votes 2,500 22 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 23, 2009, there were 745 Common Unitholders of record. The following table presents, for the periods indicated, the high and low sales prices per Common Unit, as reported on the NYSE, and the amount of quarterly cash distributions declared and paid per Common Unit in respect of each quarter. Fiscal 2009 First Quarter Second Quarter Third Quarter Fourth Quarter Fiscal 2008 First Quarter Second Quarter Third Quarter Fourth Quarter Common Unit Price Range High Low $ 35.46 41.60 42.98 46.41 $ 20.40 31.00 35.81 39.79 Cash Distribution Declared per Common Unit $ 0.8100 0.8150 0.8250 0.8300 $ 48.50 42.43 42.60 39.59 $ 40.00 34.00 37.88 33.13 $ 0.7625 0.7750 0.8000 0.8050 We make quarterly distributions to our partners in an aggregate amount equal to our Available Cash (as defined in our Partnership Agreement as adopted effective October 19, 2006, as amended) with respect to such quarter. Available Cash generally means all cash on hand at the end of the fiscal quarter plus all additional cash on hand as a result of borrowings subsequent to the end of such quarter less cash reserves established by the Board of Supervisors in its reasonable discretion for future cash requirements. We are a publicly traded limited partnership and, other than certain corporate subsidiaries, we are not subject to federal income tax. Instead, Unitholders are required to report their allocable share of our earnings or loss, regardless of whether we make distributions. (b) Not applicable. (c) None. 23 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. Statement of Operations Data Revenues Costs and expenses Restructuring charges and severance costs (b) Impairment of goodwill (c) Income before interest expense, loss on debt extinguishment and provision for income taxes (d) Interest expense, net Loss on debt extinguishment (e) Provision for income taxes Income (loss) from continuing operations (d) Discontinued operations: Gain on disposal of discontinued operations (f) Income from discontinued operations Net income (loss) Income (loss) from continuing operations per Common Unit - basic Net income (loss) per Common Unit - basic (g) Net income (loss) per Common Unit - diluted (g) Cash distributions declared per unit Balance Sheet Data (end of period) Cash and cash equivalents Current assets Total assets Current liabilities, excluding short-term borrowings and current portion of long-term borrowings Total debt Other long-term liabilities Partners' capital - Common Unitholders Partner's (deficit) capital - General Partner Statement of Cash Flows Data Cash provided by (used in) Operating activities Investing activities Financing activities September 26, 2009 September 27, 2008 Year Ended September 29, 2007 September 30, 2006 (a) September 24, 2005 $ 1,143,154 932,539 - - $ 1,574,163 1,424,035 - - $ 1,439,563 1,273,482 1,485 - $ 1,657,130 1,521,316 6,076 - $ 1,615,555 1,546,531 2,775 656 210,615 38,267 4,624 2,486 165,238 - - 165,238 150,128 37,052 - 1,903 111,173 43,707 - 154,880 164,596 35,596 - 5,653 123,347 1,887 2,053 127,287 129,738 40,680 - 764 88,294 - 2,446 90,740 65,593 40,374 36,242 803 (11,826) 976 2,774 (8,076) 4.99 4.99 4.96 3.26 $ 3.39 4.72 4.70 3.09 $ 3.79 3.91 3.89 2.76 $ 2.76 2.84 2.83 2.48 $ (0.38) (0.26) (0.26) 2.45 $ $ 163,173 307,556 977,514 $ 137,698 359,551 1,035,713 $ 96,586 295,940 988,947 $ 60,571 236,027 945,566 $ 14,411 236,803 959,305 180,059 349,415 88,323 421,005 $ - 226,056 531,772 57,809 264,231 $ - 206,011 548,538 68,121 208,230 $ - 191,195 548,304 105,366 170,151 (1,969) $ 193,851 575,295 114,043 159,199 (1,779) $ $ $ 246,551 (16,852) (204,224) $ $ 120,517 36,630 (116,035) $ $ 145,957 (19,689) (90,253) $ $ 170,321 (19,092) (105,069) $ $ 39,005 (24,631) (53,444) Other Data Depreciation and amortization - continuing operations Depreciation and amortization - discontinued operations EBITDA (h) Adjusted EBITDA (h) Capital expenditures - maintenance and growth (i) Retail gallons sold Propane Fuel oil and refined fuels $ 30,343 - 236,334 234,621 21,837 $ 28,394 - 222,229 220,465 21,819 $ 28,790 452 197,778 205,333 26,756 $ 32,653 498 165,335 150,863 23,057 $ 37,260 502 70,863 68,366 29,301 343,894 57,381 386,222 76,515 432,526 104,506 466,779 145,616 516,040 244,536 24 (a) Fiscal 2006 includes 53 weeks of operations compared to 52 weeks in each of fiscal 2009, 2008, 2007 and 2005. (b) During fiscal 2007, we incurred $1.5 million in charges associated with severance for positions eliminated unrelated to any specific plan of restructuring. During fiscal 2006, we incurred $6.1 million in restructuring charges associated primarily with severance costs from our field realignment efforts initiated during the fourth quarter of fiscal 2005, including the restructuring of our services business. During fiscal 2005, we incurred $2.8 million in restructuring charges associated primarily with severance costs from the realignment of our field operations. (c) During fiscal 2005, we recorded a non-cash charge of $0.7 million related to the impairment of goodwill in our all other category. (d) These amounts include gains from the disposal of property, plant and equipment of $0.7 million for fiscal 2009, $2.3 million for fiscal 2008, $2.8 million for fiscal 2007, $1.0 million for fiscal 2006 and $2.0 million for fiscal 2005. (e) During fiscal 2009, we purchased $175.0 million aggregate principal amount of the 2003 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. During fiscal 2005, we incurred a charge of $36.2 million as a result of our March 31, 2005 debt refinancing to reflect the loss on debt extinguishment associated with a prepayment premium of $32.0 million and the write-off of $4.2 million of unamortized bond issuance costs associated with the previously outstanding senior notes. (f) 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. Gain on disposal of discontinued operations for fiscal 2005 of $1.0 million reflects the finalization of certain purchase price adjustments with the buyer of the customer service centers sold during fiscal 2004. The gains on disposal have been accounted for within discontinued operations. Prior period results of operations attributable to the customer service centers sold during fiscal 2007 were not significant and, as such, prior period results were not reclassified to remove financial results from continuing operations. The prior period results of operations attributable to the sale of our Tirzah, South Carolina storage cavern and associated pipeline have been reclassified to remove financial results from continuing operations. (g) Computations of basic earnings per Common Unit for the years ended September 26, 2009, September 27, 2008 and September 29, 2007 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. For fiscal 2006, earnings per Common Unit were performed using the two-class method when participating securities exist, as applicable. The two-class method is an earnings allocation formula that computes earnings per unit for each class of Common Unit and participating security according to distributions declared and participating rights in undistributed earnings, as if all of the earnings were distributed to the limited partners and the General Partner (inclusive of the previously outstanding IDRs of the General Partner which were considered participating securities for purposes of the two-class method). Net income was allocated to the Common Unitholders and the General Partner in accordance with their respective partnership ownership interests, after giving effect to any priority income allocations for IDRs of the General Partner. As a result of the GP Exchange Transaction on October 19, 2006, the two-class method 25 of computing income per Common Unit under is no longer applicable. The requirements of the two-class method do not apply to the computation of earnings per Common Unit in periods in which a net loss is reported and therefore did not have any impact on loss per Common Unit for the year ended September 24, 2005. Application of the two-class method had a dilutive effect on income per Common Unit of $0.07 for the year ended September 30, 2006. Basic net loss per Common Unit for the year ended September 24, 2005 was computed by dividing net loss, after deducting our General Partner’s interest, by the weighted average number of outstanding Common Units, and restricted units granted under our restricted unit plans to retirement-eligible grantees. Diluted net loss per Common Unit for the same period was computed by dividing net loss, after deducting our General Partner’s interest, by the weighted average number of outstanding Common Units and unvested restricted units under our restricted unit plans. For purposes of the computation of income per Common Unit for the year ended September 29, 2007, earnings that would have been allocated to the General Partner for the period prior to the GP Exchange Transaction were not significant. (h) EBITDA represents net income before deducting interest expense, income taxes, depreciation and amortization. Adjusted EBITDA represents EBITDA excluding the unrealized net gain or loss on mark-to- market activity for derivative instruments. 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 generally accepted accounting principles (“GAAP”) and should not be considered as an alternative to net income or net cash provided by operating activities determined in accordance with GAAP. Because EBITDA 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): 26 Net income (loss) Add: Provision for income taxes Interest expense, net Depreciation and amortization Continuing operations Discontinued operations EBITDA Unrealized (non-cash) (gains) losses on changes in fair value of derivatives Adjusted EBITDA Add (subtract): Provision for income taxes - current Interest expense, net Loss on debt extinguishment Unrealized (non-cash) gains (losses) on changes in fair value of derivatives Compensation cost recognized under Restricted Unit Plan Gain on disposal of property, plant and equipment, net Gain on disposal of discontinued operations Pension settlement charge Changes in working capital and other assets and liabilities Fiscal 2009 Fiscal 2008 Fiscal 2007 Fiscal 2006 Fiscal 2005 $ 165,238 $ 154,880 $ 127,287 $ 90,740 $ (8,076) 2,486 38,267 30,343 - 236,334 (1,713) 234,621 (1,101) (38,267) 4,624 1,713 2,396 1,903 37,052 28,394 - 222,229 (1,764) 220,465 (626) (37,052) - 1,764 2,156 5,653 35,596 28,790 452 197,778 7,555 205,333 (1,853) (35,596) - 764 40,680 32,653 498 165,335 (14,472) 150,863 (764) (40,680) - (7,555) 14,472 3,014 2,221 803 40,374 37,260 502 70,863 (2,497) 68,366 (803) (40,374) 36,242 2,497 1,805 (650) (2,252) (2,782) (1,000) (2,043) - - (43,707) - (1,887) 3,269 - 4,437 (976) - 43,215 (20,231) (15,986) 40,772 (25,709) Net cash provided by operating activities $ 246,551 $ 120,517 $ 145,957 $ 170,321 $ 39,005 (i) 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. 27 ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following is a discussion of our financial condition and results of operations, which should be read in conjunction with our consolidated financial statements and notes thereto included elsewhere in this Annual Report. Executive Overview The following are factors that regularly affect our operating results and financial condition. In addition, our business is subject to the risks and uncertainties described in Item 1A of this Annual Report. Product Costs and Supply The level of profitability in the retail propane, fuel oil, natural gas and electricity businesses is largely dependent on the difference between retail sales price and product cost. The unit cost of our products, particularly propane, fuel oil and natural gas, is subject to volatility as a result of product supply or other market conditions, including, but not limited to, economic and political factors impacting crude oil and natural gas supply or pricing. We enter into product supply contracts that are generally one-year agreements subject to annual renewal, and we also purchase product on the open market. We attempt to reduce our exposure to volatile product costs by short-term pricing arrangements, rather than long-term fixed price supply arrangements. Our propane supply contracts typically provide for pricing based upon index formulas using the posted prices established at major supply points such as Mont Belvieu, Texas, or Conway, Kansas (plus transportation costs) at the time of delivery. To supplement our annual purchase requirements, we may utilize forward fixed price purchase contracts to acquire a portion of the propane that we resell to our customers, which allows us to manage our exposure to unfavorable changes in commodity prices and to assure adequate physical supply. The percentage of contract purchases, and the amount of supply contracted for under forward contracts at fixed prices, will vary from year to year based on market conditions. Product cost changes can occur rapidly over a short period of time and can impact profitability. There is no assurance that we will be able to pass on product cost increases fully or immediately, particularly when product costs increase rapidly. Therefore, average retail sales prices can vary significantly from year to year as product costs fluctuate with propane, fuel oil, crude oil and natural gas commodity market conditions. In addition, in periods of sustained higher commodity prices, as has been experienced over the past several fiscal years, retail sales volumes have been negatively impacted by customer conservation efforts. Seasonality The retail propane and fuel oil distribution businesses, as well as the natural gas marketing business, are seasonal because of the primary use for heating in residential and commercial buildings. Historically, approximately two-thirds of our retail propane volume is sold during the six-month peak heating season from October through March. The fuel oil business tends to experience greater seasonality given its more limited use for space heating and approximately three-fourths of our fuel oil volumes are sold between October and March. Consequently, sales and operating profits are concentrated in our first and second fiscal quarters. Cash flows from operations, therefore, are greatest during the second and third fiscal quarters when customers pay for product purchased during the winter heating season. We expect lower operating profits and either net losses or lower net income during the period from April through September (our third and fourth fiscal quarters). To the extent necessary, we will reserve cash from the second and third quarters for distribution to holders of our Common Units in the first and fourth fiscal quarters. 28 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 fuel oil and crude oil futures and option contracts traded on the New York Mercantile Exchange (“NYMEX”), to purchase and sell 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 and futures are generally settled in cash at the expiration of the contract. Although we use derivative instruments to reduce the effect of price volatility associated with priced physical inventory and forecasted transactions, we do not use derivative instruments for speculative trading purposes. Risk management activities are monitored by an internal Commodity Risk Management Committee, made up of five members of management and reporting to our Audit Committee, through enforcement of our Hedging and Risk Management Policy. Under our hedging and risk management strategy, realized gains or losses on futures or option contracts will typically offset losses or gains on the physical inventory once the product is sold to customers at market prices. However, as a result of lower than expected volumes primarily attributable to customer conservation, we realized losses under certain futures positions in fiscal 2008 that were not fully offset by sales of the physical product. Accordingly, our risk management activities had a negative effect on earnings of approximately $10.8 million during fiscal 2008 as a result of realized losses on futures contracts that were not fully offset by sales of physical product. See Item 7A of this Annual Report for a further discussion of risk management activities. Critical Accounting Policies and Estimates Our significant accounting policies are summarized in Note 2, “Summary of Significant Accounting Policies,” included within the Notes to Consolidated Financial Statements section elsewhere in this Annual Report. Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated, requiring management to make certain assumptions with respect to values or conditions that cannot be known with certainty at the time the financial statements are prepared. The preparation of financial statements in conformity with generally accepted accounting principles (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. 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 29 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 850,000 customers, no individual customer account is material. Therefore, while some variation to actual results occurs, historically such variability has not been material. Schedule II, Valuation and Qualifying Accounts, provides a summary of the changes in our allowances for doubtful accounts during the period. Pension and Other Postretirement Benefits. We estimate the rate of return on plan assets, the discount rate used to estimate the present value of future benefit obligations and the expected cost of future health care benefits in determining our annual pension and other postretirement benefit costs. While we believe that our assumptions are appropriate, significant differences in our actual experience or significant changes in market conditions may materially affect our pension and other postretirement benefit obligations and our future expense. See “Liquidity and Capital Resources - Pension Plan Assets and Obligations” below for additional disclosure regarding pension benefits. With other assumptions held constant, an increase of 100 basis points in the discount rate would have an estimated favorable impact of $0.2 million on net pension and postretirement benefit costs and an increase of 100 basis points in the expected rate of return assumption would have an estimated favorable impact of $1.2 million on net pension benefit costs. With other assumptions held constant, a decrease of 100 basis points in the discount rate would have an estimated unfavorable impact of $0.2 million on net pension and postretirement benefit costs and a decrease of 100 basis points in the expected rate of return assumption would have an estimated unfavorable impact of $1.2 million on net pension 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. 30 Results of Operations and Financial Condition Net income for fiscal 2009 amounted to $165.2 million, or $4.99 per Common Unit, an increase of $10.3 million, or 6.6%, compared to net income of $154.9 million, or $4.72 per Common Unit, in fiscal 2008. Earnings before interest, taxes, depreciation and amortization (“EBITDA”) increased $14.1 million, or 6.3%, to $236.3 million in fiscal 2009 compared to $222.2 million for fiscal 2008. 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. Net income and EBITDA for fiscal 2008 included a gain (reported within discontinued operations) of $43.7 million from the sale of our Tirzah, South Carolina underground propane storage cavern and associated 62-mile pipeline. Therefore, excluding the effects of these significant items on our earnings for both periods, EBITDA increased $62.4 million, or 35.0%, in fiscal 2009 compared to the prior year. In addition to the increased earnings, fiscal 2009 included several notable achievements, including: (i) a $185 million reduction in total debt; (ii) the refinancing of our revolving credit facility to a new four-year facility on favorable terms relative to an otherwise challenging credit market; (iii) an upgrade to our credit ratings by both Moody’s Investors Service and Standard & Poor’s; (iv) the successful issuance of 2,430,934 Common Units, the proceeds of which were used to fund a portion of the debt reduction; and, (v) an increase of $0.10 per Common Unit, or 3.1%, in the annualized distribution rate compared to the end of fiscal 2008. We ended fiscal 2009 with $163.2 million of cash on hand, an increase of $25.5 million compared to the end of fiscal 2008, despite the use of cash for a portion of the debt reduction. Revenues of $1,143.2 million decreased $431.0 million, or 27.4%, compared to $1,574.2 million in the prior year, primarily as a result of a decline in average selling prices associated with lower commodity prices and, to a lesser extent, lower sales volumes. Retail propane gallons sold for fiscal 2009 decreased 42.3 million gallons, or 11.0%, to 343.9 million gallons from 386.2 million gallons in fiscal 2008. Sales of fuel oil and other refined fuels decreased 19.1 million gallons, or 25.0%, to 57.4 million gallons compared to 76.5 million gallons in the prior year. Overall average temperatures in our service territories for fiscal 2009 were 5% colder than the prior year. The favorable volume impact from the colder average temperatures was more than offset by declines in commercial and industrial volumes resulting from the recession and, to a lesser extent, continued customer conservation. In the commodities markets, average posted prices for propane and fuel oil during fiscal 2009 were 51.7% and 46.1% lower, respectively, compared to fiscal 2008. Cost of products sold declined $499.0 million, or 48.0%, to $540.4 million in fiscal 2009 compared to $1,039.4 million in the prior year. The sharp decline in commodity prices, particularly during the first half of fiscal 2009, compared to the historically high commodity prices reached during fiscal 2008, resulted in a reduction in product costs that outpaced the decline in average selling prices. In addition, during fiscal 2008 we reported realized losses from risk management activities that were not fully offset by sales of the physical product, resulting in a $10.8 million reduction to cost of products sold in fiscal 2009 compared to the prior year. Cost of products sold for fiscal 2009 and fiscal 2008 included a $1.7 million and $1.8 million unrealized (non-cash) gain, respectively, attributable to the mark-to-market adjustment for derivative instruments used in risk management activities. Combined operating and general and administrative expenses of $361.8 million increased $5.6 million, or 1.6%, compared to $356.2 million in the prior year, primarily due to higher variable compensation associated with higher earnings, partially offset by continued savings in payroll and vehicle expenses attributable to further operating efficiencies and lower diesel costs, as well as lower bad debt expense. Net interest expense increased $1.2 million, or 3.2%, to $38.3 million in fiscal 2009 compared to $37.1 million in fiscal 2008 as a result of lower interest income earned on invested cash. With the $175 million debt tender offer which was completed on September 9, 2009, we have reduced our interest expense requirement by approximately $12.0 million on an annualized basis beginning in fiscal 2010. As has been the case since April 2006, during fiscal 2009 there were no borrowings under our revolving credit facility to support working capital 31 needs, as such needs continue to be funded from cash on hand. As we look ahead to fiscal 2010, our anticipated cash requirements include: (i) maintenance and growth capital expenditures of approximately $25.0 million; (ii) approximately $28.1 million of interest and income tax payments; and (iii) assuming distributions remain at the current level, approximately $117.2 million of distributions to Common Unitholders. Based on our current cash position, availability under the Revolving Credit Agreement (unused borrowing capacity of $92.8 million at September 26, 2009) 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 2010, we currently do not expect to borrow under our credit facility to fund those requirements. Fiscal Year 2009 Compared to Fiscal Year 2008 Revenues (Dollars in thousands) Revenues Propane Fuel oil and refined fuels Natural gas and electricity All other Total revenues Fiscal 2009 Fiscal 2008 (Decrease) Percent (Decrease) $ 864,012 159,596 76,832 42,714 1,143,154 $ $ 1,132,950 288,078 103,745 49,390 1,574,163 $ $ (268,938) (128,482) (26,913) (6,676) (431,009) $ (23.7%) (44.6%) (25.9%) (13.5%) (27.4%) Total revenues decreased $431.0 million, or 27.4%, to $1,143.2 million for the year ended September 26, 2009 compared to $1,574.2 million for the year ended September 27, 2008, due to a combination of lower volumes and lower average selling prices associated with lower product costs. Volumes for the fiscal 2009 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 ongoing customer conservation, partially offset by the favorable impact of colder temperatures. From a weather perspective, average heating degree days, as reported by the National Oceanic and Atmospheric Administration) in our service territories were 99% of normal for fiscal 2009 and 5% colder compared to the prior year. Revenues from the distribution of propane and related activities of $864.0 million for the year ended September 26, 2009 decreased $268.9 million, or 23.7%, compared to $1,133.0 million for the year ended September 27, 2008, primarily due to lower average selling prices, as well as lower volumes in our commercial and industrial accounts and, to a lesser extent, our residential accounts. Retail propane gallons sold in fiscal 2009 decreased 42.3 million gallons, or 11.0%, to 343.9 million gallons from 386.2 million gallons in the prior year. The average propane selling prices during fiscal 2009 decreased approximately 14.0% compared to the prior year due to lower product costs, thereby having a negative impact on revenues. Additionally, revenues from wholesale and other propane activities of $43.4 million for the year ended September 26, 2009 decreased $18.3 million compared to the prior year. Revenues from the distribution of fuel oil and refined fuels of $159.6 million for the year ended September 26, 2009 decreased $128.5 million, or 44.6%, from $288.1 million in the prior year, primarily due to lower volumes and lower average selling prices. Fuel oil and refined fuels gallons sold in fiscal 2009 decreased 19.1 million gallons, or 25.0%, to 57.4 million gallons from 76.5 million gallons in the prior year. Lower volumes in our fuel oil and refined fuels segment were primarily attributable to the impact of ongoing customer conservation driven by adverse economic conditions and continued high energy prices relative to historical averages. The 32 average fuel oil and refined fuels selling prices during fiscal 2009 decreased approximately 26.9% compared to the prior year due to lower product costs, thereby having a negative impact on revenues. Revenues in our natural gas and electricity segment decreased $26.9 million, or 25.9%, to $76.8 million for the year ended September 26, 2009 compared to $103.7 million in the prior year as a result of lower average selling prices and lower volumes. Revenues in our all other segment decreased 13.5% to $42.7 million in fiscal 2009 from $49.4 million in the prior year, primarily due to reduced installation service activities as a result of the market decline in residential and commercial construction and other adverse economic conditions. Cost of Products Sold (Dollars in thousands) Cost of products sold Propane Fuel oil and refined fuels Natural gas and electricity All other Total cost of products sold Fiscal 2009 Fiscal 2008 (Decrease) Percent (Decrease) $ $ 367,016 104,634 57,216 11,519 540,385 $ 689,921 247,310 87,600 14,605 1,039,436 $ $ (322,905) (142,676) (30,384) (3,086) (499,051) $ (46.8%) (57.7%) (34.7%) (21.1%) (48.0%) As a percent of total revenues 47.3% 66.0% The cost of products sold reported in the consolidated statements of operations represents the weighted average unit cost of propane and fuel oil sold, as well as the cost of natural gas and electricity, including transportation costs to deliver product from our supply points to storage or to our customer service centers. Cost of products sold also includes the cost of appliances and related parts sold or installed by our customer service centers computed on a basis that approximates the average cost of the products. Unrealized (non-cash) gains or losses from changes in the fair value of derivative instruments that are not designated as cash flow hedges are recorded within cost of products sold. Cost of products sold excludes depreciation and amortization; these amounts are reported separately within the consolidated statements of operations. Cost of products sold decreased $499.0 million, or 48.0%, to $540.4 million for the year ended September 26, 2009 compared to $1,039.4 million in the prior year due to the impact of the decline in product costs, lower volumes sold and the favorable impact from our risk management activities (during fiscal 2008 we reported realized losses from risk management activities that were not fully offset by sales of the physical product, resulting in a $10.8 million reduction to cost of products sold in fiscal 2009 compared to the prior year). Cost of products sold in fiscal 2009 and fiscal 2008 included a $1.7 million and $1.8 million unrealized (non-cash) gain, respectively, representing the net change in the fair value of derivative instruments during the period ($3.1 million increase in cost of products sold reported within the propane segment, offset by a $3.0 million decrease in cost of products sold within the fuel oil and refined fuels segment). Cost of products sold associated with the distribution of propane and related activities of $367.0 million for the year ended September 26, 2009 decreased $322.9 million, or 46.8%, compared to the prior year. Lower average propane costs and lower propane volumes resulted in a decrease of $234.1 million and $71.8 million, respectively, in cost of products sold during fiscal 2009 compared to the prior year. Cost of products sold from wholesale and other propane activities decreased $20.1 million compared to the prior year due to lower product costs and lower sales volumes. 33 Cost of products sold associated with the distribution of fuel oil and refined fuels of $104.6 million for the year ended September 26, 2009 decreased $142.7 million, or 57.7%, compared to the prior year. Lower average fuel oil and refined fuels costs and lower volumes resulted in decreases of $72.7 million and $56.2 million, respectively, in cost of products sold during fiscal 2009 compared to the prior year. In addition, during fiscal 2008 we reported realized losses from risk management activities that were not fully offset by sales of the physical product, resulting in a $10.8 million reduction to cost of products sold associated with our fuel oil and refined fuels segment in fiscal 2009 compared to the prior year. Cost of products sold in our natural gas and electricity segment of $57.2 million for the year ended September 26, 2009 decreased $30.4 million, or 34.7%, compared to the prior year due to lower product costs and lower sales volumes. Cost of products sold in our all other segment of $11.5 million for the year ended September 26, 2009 decreased $3.1 million, or 21.1%, compared to the prior year primarily due to lower sales volumes. For the fiscal year ended September 26, 2009, total cost of products sold represented 47.3% of revenues compared to 66.0% in the prior year. The decrease in costs as a percentage of revenues was primarily attributable to the decline in product costs which outpaced the decline in average selling prices, and, to a much lesser extent, the favorable variance attributable to risk management activities discussed above. Operating Expenses (Dollars in thousands) Operating expenses As a percent of total revenues Fiscal 2009 304,767 26.7% $ Fiscal 2008 308,071 19.6% $ (Decrease) $ (3,304) Percent (Decrease) (1.1%) 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 $304.8 million for year ended September 26, 2009 decreased $3.3 million, or 1.1%, compared to $308.1 million in the prior year as higher variable compensation expense associated with higher earnings was more than offset by our continued efforts to drive operational efficiencies and reduce costs across all operating segments. Savings were primarily attributable to payroll and benefit related expenses as a result of lower headcount, lower fuel costs to operate our fleet and lower bad debt expense. General and Administrative Expenses (Dollars in thousands) General and administrative expenses As a percent of total revenues Fiscal 2009 Fiscal 2008 $ 57,044 5.0% $ 48,134 3.1% Increase $ 8,910 Percent Increase 18.5% 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 34 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 $57.0 million for the year ended September 26, 2009 increased $8.9 million, or 18.5%, compared to $48.1 million during the prior year. The increase was primarily attributable to higher variable compensation expense resulting from higher earnings in fiscal 2009 compared to the prior year, and higher compensation costs recognized under certain long-term incentive plans. Depreciation and Amortization (Dollars in thousands) Depreciation and amortization As a percent of total revenues Fiscal 2009 Fiscal 2008 $ 30,343 2.7% $ 28,394 1.8% Increase $ 1,949 Percent Increase 6.9% Depreciation and amortization expense of $30.4 million for the year ended September 26, 2009 increased $1.9 million, or 6.9%, compared to $28.4 million in the prior year primarily as a result of accelerating depreciation expense for certain assets retired in the second half of fiscal 2009. Interest Expense, net (Dollars in thousands) Interest expense, net As a percent of total revenues Fiscal 2009 Fiscal 2008 $ 38,267 3.3% $ 37,052 2.4% Increase $ 1,215 Percent Increase 3.3% Net interest expense increased $1.2 million, or 3.3%, to $38.3 million for the year ended September 26, 2009, compared to $37.1 million in the prior year as a result of lower market interest rates for short-term investments, which contributed to less interest income earned, and a non-cash charge of $0.4 million to write-off the unamortized debt issuance costs associated with the previous credit agreement which was terminated in the third quarter of fiscal 2009. Loss on Debt Extinguishment On September 9, 2009, we purchased $175,000 aggregate principal amount of the 2003 Senior Notes through a cash tender offer. In connection with the tender offer, we recognized a loss on the extinguishment of debt of $4,624 in the fourth quarter of fiscal 2009, consisting of $2,821 for the tender premium and related fees, as well as the write-off of $1,803 in unamortized debt origination costs and unamortized discount. Discontinued Operations On October 2, 2007, the Operating Partnership completed the sale of its Tirzah, South Carolina underground granite propane storage cavern, and associated 62-mile pipeline, for approximately $53.7 million in cash, after taking into account certain adjustments. As part of the agreement, we entered into a long-term storage arrangement, not to exceed 7 million propane gallons, with the purchaser of the cavern that will enable us to continue to meet the needs of our retail operations, consistent with past practices. As a result of this sale, we reported a $43.7 million gain on disposal of discontinued operations during the first quarter of fiscal 2008. 35 Net Income and EBITDA We reported net income of $165.2 million, or $4.99 per Common Unit, for the year ended September 26, 2009 compared to net income of $154.9 million, or $4.72 per Common Unit, in the prior year. EBITDA for fiscal 2008 of $236.3 million increased $14.1 million, or 6.3%, compared to EBITDA of $222.2 million in the prior year. Net income and EBITDA for fiscal 2009 included a $4.6 million charge for the loss on extinguishment of $175 million of our 6.875% Senior Notes. By comparison, net income and EBITDA for fiscal 2008 included a gain (reported within discontinued operations) of $43.7 million from our sale of its Tirzah, South Carolina underground storage cavern and associated 62-mile pipeline. EBITDA represents net income before deducting interest expense, income taxes, depreciation and amortization. Our management uses EBITDA as a measure of liquidity and we disclose it because we believe that it provides our investors and industry analysts with additional information to evaluate our ability to meet our debt service obligations and to pay our quarterly distributions to holders of our Common Units. In addition, certain of our incentive compensation plans covering executives and other employees utilize EBITDA as the performance target. We use this non-GAAP financial measure in order to assist industry analysts and investors in assessing our liquidity on a year-over-year basis. Moreover, our revolving credit agreement requires us to use EBITDA as a component in calculating our leverage and interest coverage ratios. EBITDA is not a recognized term under GAAP and should not be considered as an alternative to net income or net cash provided by operating activities determined in accordance with GAAP. Because EBITDA as determined by us excludes some, but not all, items that affect net income, it may not be comparable to EBITDA or similarly titled measures used by other companies. The following table sets forth (i) our calculations of EBITDA and (ii) a reconciliation of EBITDA, as so calculated, to our net cash provided by operating activities: 36 (Dollars in thousands) Net income Add: Provision for income taxes Interest expense, net Depreciation and amortization EBITDA Unrealized (non-cash) (gains) on changes in fair Adjusted EBITDA Add (subtract): Provision for income taxes - current Interest expense, net Loss on debt extinguishment Unrealized (non-cash) gains on changes in fair Compensation cost recognized under Restricted Unit Plan Gain on disposal of property, plant and equipment, net Gain on disposal of discontinued operations Changes in working capital and other assets and liabilities Year Ended September 26, 2009 September 27, 2008 $ 165,238 $ 154,880 2,486 38,267 30,343 236,334 (1,713) 234,621 (1,101) (38,267) 4,624 1,713 2,396 (650) - 43,215 1,903 37,052 28,394 222,229 (1,764) 220,465 (626) (37,052) - 1,764 2,156 (2,252) (43,707) (20,231) Net cash provided by operating activities $ 246,551 $ 120,517 Fiscal Year 2008 Compared to Fiscal Year 2007 Revenues (Dollars in thousands) Revenues Propane Fuel oil and refined fuels Natural gas and electricity All other Total revenues Fiscal 2008 Fiscal 2007 Increase / (Decrease) $ $ 1,132,950 288,078 103,745 49,390 1,574,163 $ 1,019,798 262,076 94,352 63,337 1,439,563 $ $ $ 113,152 26,002 9,393 (13,947) 134,600 Percent Increase / (Decrease) 11.1% 9.9% 10.0% (22.0%) 9.4% Total revenues increased $134.6 million, or 9.4%, to $1,574.2 million for the year ended September 27, 2008 compared to $1,439.6 million for the year ended September 29, 2007, due to higher average selling prices associated with higher product costs, partially offset by lower volumes. Volumes in our propane, fuel oil and refined fuels and natural gas and electricity segments were lower in fiscal 2008 compared to the prior year primarily due to ongoing customer conservation resulting from the historically high commodity prices, proactive steps to manage customer credit risk, warmer weather in our service territories during the peak heating months and, to a lesser extent, the effects of eliminating certain lower margin accounts which occurred throughout much 37 of the prior year. From a weather perspective, average heating degree days in our service territories were 94% of normal for fiscal 2008 and flat compared to the prior year; however, the winter heating season of fiscal 2008 was warmer than the comparable prior year period, particularly in the northeast where average heating degree days were 7% below normal and the prior year, thus having a negative effect on volumes. Revenues from the distribution of propane and related activities of $1,133.0 million for the year ended September 27, 2008 increased $113.2 million, or 11.1%, compared to $1,019.8 million for the year ended September 29, 2007, primarily due to higher average selling prices, partially offset by lower volumes. Retail propane gallons sold in fiscal 2008 decreased 46.3 million gallons, or 10.7%, to 386.2 million gallons from 432.5 million gallons in the prior year. The average posted price of propane during fiscal 2008 increased 48.6% compared to the average posted prices in the prior year, while our average propane selling prices during fiscal 2008 increased approximately 27.0% compared to the prior year. Additionally, revenues from wholesale and other propane activities for the year ended September 27, 2008 decreased $13.2 million compared to the prior year. Revenues from the distribution of fuel oil and refined fuels of $288.1 million for the year ended September 27, 2008 increased $26.0 million, or 9.9%, from $262.1 million in the prior year, primarily due to higher average selling prices, partially offset by lower volumes. Fuel oil and refined fuels gallons sold in fiscal 2008 decreased 28.0 million gallons, or 26.8%, to 76.5 million gallons from 104.5 million gallons in the prior year. Lower volumes in our fuel oil and refined fuels segment were attributable to the impact of ongoing customer conservation from continued high energy prices combined with our decision to exit certain lower margin diesel and gasoline businesses. Our decision to exit the majority of our low sulfur diesel and gasoline businesses resulted in a reduction in volumes in the fuel oil and refined fuels segment of approximately 9.7 million gallons, or 34.5% of the total volume decline in fiscal 2008 compared to the prior year. The average posted price of fuel oil during fiscal 2008 increased approximately 63.8% compared to the average posted prices in the prior year, while our average selling prices in our fuel oil and refined fuels segment increased approximately 47.4% compared to the prior year period. Revenues in our natural gas and electricity segment increased $9.3 million, or 10.0%, to $103.7 million for the year ended September 27, 2008 compared to $94.4 million in the prior year as a result of higher average selling prices for both electricity and natural gas, partially offset by lower electricity and natural gas volumes. Revenues in our all other segment decreased 22.0% to $49.4 million in fiscal 2008 from $63.3 million in the prior year as a result of the decision to reduce the level of certain installation service activities. The focus of our ongoing service offerings are in support of our existing core commodity segments. Cost of Products Sold (Dollars in thousands) Cost of products sold Propane Fuel oil and refined fuels Natural gas and electricity All other Total cost of products sold Fiscal 2008 Fiscal 2007 Increase / (Decrease) $ 689,921 247,310 87,600 14,605 1,039,436 $ $ $ 573,305 194,213 77,116 20,784 865,418 116,616 53,097 10,484 (6,179) 174,018 $ $ Percent Increase / (Decrease) 20.3% 27.3% 13.6% (29.7%) 20.1% As a percent of total revenues 66.0% 60.1% Cost of products sold in fiscal 2008 included a $1.8 million unrealized (non-cash) gain representing the net 38 unrealized change in the fair value of derivative instruments during the period, compared to a $7.6 million unrealized (non-cash) loss in the prior year resulting in a decrease of $9.4 million in cost of products sold for the year ended September 27, 2008 compared to the prior year. Cost of products sold associated with the distribution of propane and related activities of $689.9 million increased $116.6 million, or 20.3%, compared to the prior year. Higher average propane costs resulted in an increase of $189.8 million in cost of products sold during fiscal 2008 compared to the prior year. The impact of the sharp increase in commodity prices was partially offset by lower propane volumes which resulted in a $55.8 million decrease in cost of products sold during fiscal 2008 compared to the prior year. Lower wholesale and other propane revenues, noted above, decreased cost of products sold by approximately $14.2 million compared to the prior year. In addition, the portion of the total net change in the fair value of derivative instruments associated with the propane segment during fiscal 2008, noted above, resulted in a $3.2 million decrease in cost of products sold compared to the prior year. Cost of products sold associated with our fuel oil and refined fuels segment of $247.3 million increased $53.1 million, or 27.3%, compared to the prior year. Higher average fuel oil costs resulted in an increase of $101.8 million in cost of products sold during fiscal 2008 compared to the prior year period. This increase was partially offset by lower fuel oil sales volumes, which resulted in a $53.3 million decrease in cost of products sold during fiscal 2008 compared to the prior year. In addition, as described above, risk management activities during fiscal 2008 resulted in a $10.8 million increase in cost of products sold compared to the prior year as a result of realized losses on futures contracts that were not fully offset by sales of physical product. The portion of the total net change in the fair value of derivative instruments associated with the fuel oil and refined fuels segment during the period resulted in a $6.2 million decrease in cost of products sold compared to the prior year. Cost of products sold in our natural gas and electricity segment of $87.6 million increased $10.5 million, or 13.6%, compared to the prior year due to higher average electricity costs and, to a lesser extent, natural gas costs. Cost of products sold in our all other segment of $14.6 million decreased $6.2 million, or 29.7%, compared to the prior year primarily due to lower sales volumes. For the year ended September 27, 2008, total cost of products sold represented 66.0% of revenues compared to 60.1% in the prior year. This increase was primarily attributable to the significant increase in product costs which we were not able to fully pass on to customers, as well as the favorable market conditions discussed above that contributed approximately $14.7 million of incremental margin opportunities in the prior year that were not present in fiscal 2008 and the negative effect of higher commodity prices on our risk management activities which resulted in $10.8 million of realized losses during the second half of fiscal 2008 that were not fully offset by sales of physical product. Operating Expenses (Dollars in thousands) Operating expenses As a percent of total revenues Fiscal 2008 308,071 19.6% $ Fiscal 2007 322,852 22.4% $ Decrease $ (14,781) Percent Decrease (4.6%) Operating expenses of $308.1 million for the year ended September 27, 2008 decreased $14.8 million, or 4.6%, compared to $322.9 million in the prior year as a result of our continued efforts to drive operational efficiencies and reduce costs across all operating segments. Payroll and benefit related expenses declined $18.8 million due to lower headcount, as well as lower variable compensation associated with lower earnings in fiscal 2008 compared to the prior year. In addition, vehicle expenditures decreased $0.6 million compared to the prior 39 year, despite a significant increase in the cost of diesel fuel, as a result of a lower vehicle count enabled by ongoing routing efficiencies. Savings from payroll and benefit related expenses and vehicle expenditures were partially offset by higher bad debt expense and increased costs to operate our customer service centers in the high energy price environment. General and Administrative Expenses (Dollars in thousands) General and administrative expenses As a percent of total revenues Fiscal 2008 Fiscal 2007 $ 48,134 3.1% $ 56,422 3.9% Decrease $ (8,288) Percent Decrease (14.7%) General and administrative expenses of $48.1 million for the year ended September 27, 2008 decreased $8.3 million, or 14.7%, compared to $56.4 million during the prior year. The decrease was primarily attributable to a reduction in variable compensation resulting from lower earnings in fiscal 2008 compared to the prior year and the reduction of compensation costs recognized under certain long-term incentive plans. Restructuring Charges and Severance Costs We did not record any restructuring charges for the year ended September 27, 2008. For the year ended September 29, 2007, we recorded a charge of $1.5 million primarily related to employee termination costs incurred as a result of further refinements to our plan to restructure our services business. Depreciation and Amortization (Dollars in thousands) Depreciation and amortization As a percent of total revenues Fiscal 2008 Fiscal 2007 $ 28,394 1.8% $ 28,790 2.0% Decrease $ (396) Percent Decrease (1.4%) Depreciation and amortization expense of $28.4 million for the year ended September 27, 2008 was relatively unchanged compared to the prior year. Interest Expense, net (Dollars in thousands) Interest expense, net As a percent of total revenues Fiscal 2008 Fiscal 2007 $ 37,052 2.4% $ 35,596 2.5% Increase $ 1,456 Percent Increase 4.1% Net interest expense increased $1.5 million, or 4.1%, to $37.1 million for the year ended September 27, 2008, compared to $35.6 million in the prior year as a result of lower market interest rates for short-term investments, which contributed to less interest income earned. As has been the case since April 2006, there were no borrowings under our working capital facility as seasonal working capital needs have been funded through cash 40 on hand and cash flow from operations. We ended fiscal 2008 in a strong cash position with $137.7 million in cash on the consolidated balance sheet. Discontinued Operations On October 2, 2007, the Operating Partnership completed the sale of its Tirzah, South Carolina underground granite propane storage cavern, and associated 62-mile pipeline, for approximately $53.7 million in cash, after taking into account certain adjustments. As part of the agreement, we entered into a long-term storage arrangement, not to exceed 7 million propane gallons, with the purchaser of the cavern that will enable us to continue to meet the needs of our retail operations, consistent with past practices. As a result of this sale, we reported a $43.7 million gain on disposal of discontinued operations during the first quarter of fiscal 2008. The results of operations from the Tirzah facilities have been reported within discontinued operations on the consolidated statements of operations for fiscal 2007 and the assets and liabilities have been classified as held for sale on the consolidated balance sheet as of September 29, 2007. During the first quarter of fiscal 2007, in a non-cash transaction, we disposed of nine customer service centers considered to be non-strategic in exchange for three customer service centers of another company located in Alaska. We reported a $1.0 million gain within discontinued operations during the first quarter of fiscal 2007 for the amount by which the fair value of assets relinquished exceeded the carrying value of the assets relinquished. During fiscal 2007 we also sold three customer service centers for net cash proceeds of $1.3 million and reported a gain on sale within discontinued operations of $0.9 million. Net Income and EBITDA We reported net income of $154.9 million, or $4.72 per Common Unit, for the year ended September 27, 2008 compared to net income of $127.3 million, or $3.91 per Common Unit, in the prior year. EBITDA for fiscal 2008 of $222.2 million increased $24.4 million, or 12.3%, compared to EBITDA of $197.8 million in the prior year. Net income and EBITDA for fiscal 2008 included a gain (reported within discontinued operations) of $43.7 million from our sale of its Tirzah, South Carolina underground storage cavern and associated 62-mile pipeline. By comparison, net income and EBITDA for fiscal 2007 included (i) the non-cash pension settlement charge of $3.3 million; (ii) severance costs of $1.5 million related to positions eliminated; (iii) a gain of $2.0 million from the recovery of a substantial portion of legal fees associated with the successful defense of a matter following the 1999 acquisition of certain propane assets in North and South Carolina; (iv) gains (reported within discontinued operations) of $1.9 million from the sale and exchange of customer service centers considered to be non- strategic; and (v) a non-cash adjustment to the provision for income taxes of $3.8 million. 41 The following table sets forth (i) our calculations of EBITDA and (ii) a reconciliation of EBITDA, as so calculated, to our net cash provided by operating activities: (Dollars in thousands) Net income Add: Provision for income taxes Interest expense, net Depreciation and amortization - continuing operations Depreciation and amortization - discontinued operations EBITDA Unrealized (non-cash) (gains) losses on changes Adjusted EBITDA Add (subtract): Provision for income taxes - current Interest expense, net Unrealized (non-cash) gains (losses) on changes Compensation cost recognized under Restricted Unit Plan Gain on disposal of property, plant and equipment, net Gain on disposal of discontinued operations Pension settlement charge Changes in working capital and other assets and liabilities Year Ended September 27, 2008 September 29, 2007 $ 154,880 $ 127,287 1,903 37,052 28,394 - 222,229 (1,764) 220,465 (626) (37,052) 1,764 2,156 (2,252) (43,707) - (20,231) 5,653 35,596 28,790 452 197,778 7,555 205,333 (1,853) (35,596) (7,555) 3,014 (2,782) (1,887) 3,269 (15,986) Net cash provided by operating activities $ 120,517 $ 145,957 Liquidity and Capital Resources Analysis of Cash Flows Operating Activities. Net cash provided by operating activities for the year ended September 26, 2009 amounted to $246.6 million, an increase of $126.1 million compared to $120.5 million in the prior year. The increase was attributable to a $63.2 million increase in earnings, after adjusting for non-cash items in both periods (deprecation, amortization, compensation costs recognized under our Restricted Unit Plan, gains on disposal of assets and deferred tax provision), coupled with a $62.9 million reduction in our investment in working capital as a result of the decline in propane and fuel oil commodity prices. Net cash provided by operating activities for the year ended September 27, 2008 amounted to $120.5 million, a decrease of $25.5 million compared to $146.0 million in fiscal 2007. The decrease was attributable to a $21.2 million decrease in earnings, after adjusting for non-cash items in both periods (deprecation, amortization, compensation costs recognized under our Restricted Unit Plan, gains on disposal of assets, pension settlement charges and deferred tax provision) and a $29.3 million increased investment in working capital, partially offset by a $25.0 million voluntary contribution to our defined benefit pension plan made in fiscal 2007. No pension contributions were made during fiscal 2009 or fiscal 2008. Investing Activities. Net cash used in investing activities of $16.9 million for the year ended September 26, 2009 consisted of capital expenditures of $21.8 million (including $12.2 million for maintenance expenditures 42 and $9.6 million to support the growth of operations), partially offset by the net proceeds from the sale of property, plant and equipment of $4.9 million. Capital spending in fiscal 2009 was flat compared to fiscal 2008. Net cash provided by investing activities of $36.6 million for the year ended September 27, 2008 consisted of the net proceeds from the sale of discontinued operations of $53.7 million and the net proceeds from the sale of property, plant and equipment of $4.7 million, partially offset by capital expenditures of $21.8 million (including $12.0 million for maintenance expenditures and $9.8 million to support the growth of operations). Capital spending in fiscal 2008 decreased $5.0 million, or 18.7%, compared to fiscal 2007 primarily as a result of lower spending on tanks and information technology as much of the incremental spending on our field realignment efforts has been incurred. Financing Activities. Net cash used in financing activities for the year ended September 26, 2009 of $204.2 million reflects $106.7 million in quarterly distributions to Common Unitholders at a rate of $0.805 per Common Unit in respect of the fourth quarter of fiscal 2008, at a rate of $0.81 per Common Unit in respect of the first quarter of fiscal 2009, at a rate of $0.815 per Common Unit in respect of the second quarter of fiscal 2009 and at a rate of $0.825 per Common Unit in respect of the third quarter of fiscal 2009. In addition, financing activities for fiscal 2009 reflects $110.0 million of repayments on our term loan, which was partially funded by borrowings of $100.0 million under the revolving credit facility executed on June 26, 2009; the $5.5 million payment of debt issuance costs associated with the execution of the new revolving credit facility; and the repurchase of $175.0 million aggregate principal amount of our 6.875% Senior Notes for $177.8 million, which was partially funded by the proceeds of $95.9 million from the issuance of 2,430,934 of our Common Units. Net cash used in financing activities for the year ended September 27, 2008 of $116.0 million reflects $101.0 million in quarterly distributions to Common Unitholders at a rate of $0.75 per Common Unit in respect of the fourth quarter of fiscal 2007, at a rate of $0.7625 per Common Unit in respect of the first quarter of fiscal 2008, at a rate of $0.775 per Common Unit in respect of the second quarter of fiscal 2008 and at a rate of $0.80 per Common Unit in respect of the third quarter of fiscal 2008, as well as a prepayment of $15.0 million to reduce amounts outstanding under our previous term loan. 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. These transactions increased the total number of Common Units outstanding by 2,430,934 to 35,227,954. Summary of Long-Term Debt Obligations and Revolving Credit Lines As of September 26, 2009, our long-term borrowings and revolving credit lines consist of $250.0 million in 6.875% senior notes due December 2013 (the “2003 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 replaces 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 43 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 $57.2 million primarily in support of retention levels under our self-insurance programs, which expire periodically through April 15, 2010. Therefore, as of September 26, 2009 we had available borrowing capacity of $92.8 million under the Revolving Credit Facility. On September 9, 2009, with proceeds of $95.9 million from our Equity Offering along with cash on hand, we purchased $175.0 million of our 2003 Senior Notes through a cash tender offer. Holders who validly tendered their 2003 Senior Notes on or prior to the early tender date of August 21, 2009 received a cash payment of $1,012.50 for each $1,000 principal amount of 2003 Senior Notes accepted for payment, and holders who validly tendered their 2003 Senior Notes thereafter, but on or prior to the expiration date of September 8, 2009, received a cash payment of $982.50 for each $1,000 principal amount of 2003 Senior Notes accepted for payment. The remaining $250 million of 2003 Senior Notes mature on December 15, 2013 and require semi-annual interest payments. We are permitted to redeem some or all of the 2003 Senior Notes any time on or after December 15, 2008 at redemption prices specified in the indenture governing the 2003 Senior Notes. In addition, the 2003 Senior Notes have a change of control provision that would require us to offer to repurchase the notes at 101% of the principal amount repurchased, if the holders of the notes elected to exercise the right of repurchase. Borrowings under the Revolving Credit 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 ½ 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 26, 2009, the interest rate for the Revolving Credit Facility was approximately 4.1%. The interest rate and the applicable margin will be reset at the end of each calendar quarter. In connection with the Revolving Credit Facility, our Operating Partnership amended its existing interest rate swap agreement, which has a termination date of March 31, 2010, to reduce the notional amount to $100.0 million from $108.0 million. Our Operating Partnership will pay a fixed interest rate of 4.66% to the issuing lender on the notional principal amount outstanding, effectively fixing the LIBOR portion of the interest rate at 4.66%. In return, the issuing lender will pay to our Operating Partnership a floating rate, namely LIBOR, on the same notional principal amount. On July 31, 2009, our Operating Partnership entered into a forward starting interest rate swap agreement with a March 31, 2010 effective date, which is commensurate with the maturity of the existing interest rate swap agreement, and termination date of June 25, 2013. Under the forward starting 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. The Revolving Credit Facility and the 2003 Senior Notes both contain various restrictive and affirmative covenants applicable to the Operating Partnership and the Partnership, respectively, including (i) restrictions on the incurrence of additional indebtedness, and (ii) restrictions on certain liens, investments, guarantees, loans, advances, payments, mergers, consolidations, distributions, sales of assets and other transactions. 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 2003 Senior Note indenture, we are generally permitted to make cash distributions equal to available cash, as defined, as of the end of the immediately preceding quarter, if no event of default exists or would exist upon making such distributions, and the Partnership’s consolidated fixed charge coverage ratio, as defined, is greater than 1.75 to 1. 44 We were in compliance with all covenants and terms of the 2003 Senior Notes and the Revolving Credit Facility as of September 26, 2009. Partnership Distributions We are required to make distributions in an amount equal to all of our Available Cash, as defined in the Partnership Agreement, as amended, no more than 45 days after the end of each fiscal quarter to holders of record on the applicable record dates. Available Cash, as defined in the Partnership Agreement, generally means all cash on hand at the end of the respective fiscal quarter less the amount of cash reserves established by the Board of Supervisors in its reasonable discretion for future cash requirements. These reserves are retained for the proper conduct of our business, the payment of debt principal and interest and for distributions during the next four quarters. The Board of Supervisors reviews the level of Available Cash on a quarterly basis based upon information provided by management. On October 22, 2009, we announced a quarterly distribution of $0.83 per Common Unit, or $3.32 on an annualized basis, in respect of the fourth quarter of fiscal 2009 payable on November 10, 2009 to holders of record on November 3, 2009. This quarterly distribution included an increase of $0.005 per Common Unit, or $0.02 per Common Unit on an annualized basis, from the previous quarterly distribution rate representing the twenty-third increase since our recapitalization in 1999 and a 3.1% increase in the quarterly distribution rate since the fourth quarter of the prior year. Pension Plan Assets and Obligations Our defined benefit pension plan was frozen to new participants effective January 1, 2000 and, in furtherance of our effort to minimize future increases in our benefit obligations, effective January 1, 2003, all future service credits were eliminated. Therefore, eligible participants will receive interest credits only toward their ultimate defined benefit under the defined benefit pension plan. There were no minimum funding requirements for the defined benefit pension plan during fiscal 2009, 2008 or 2007. As of September 26, 2009 the plan’s projected benefit obligation exceeded the fair value of plan assets by $17.1 million. Conversely, as of September 27, 2008 the fair value of plan assets exceeded the projected benefit obligation by $0.1 million. As a result, the funded status of the defined benefit pension plan declined $17.2 million during fiscal 2009, 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 2009. 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. During fiscal 2007, the Benefits Committee proposed and the Board of Supervisors approved contributions to the plan to improve the funded status of the projected benefit obligation and changed the plan’s asset allocation to reduce investment risk and more closely match the expected returns on plan assets to the future cash requirements of the plan. The implementation of this strategy resulted in a $25.0 million voluntary contribution in fiscal 2007 from cash on hand and changed the asset allocation to reflect a greater concentration of fixed income securities. The shift in investment strategy to a higher concentration of fixed income securities was 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 2009 and fiscal 2008, 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, we decreased the discount rate to 5.125% as of September 26, 2009 from 7.625% as of September 27, 2008, reflecting current market rates for debt obligations of a similar duration to our pension obligations. The impact of the 250 basis points reduction in the 45 discount rate on the projected benefit obligation significantly exceeded the actual return on plan assets of 14.1% in fiscal 2009, thus substantially contributing to the reduction in the funded status of the plan. For purposes of computing net periodic pension cost for fiscal 2009, 2008 and 2007, our assumed long-term rate of return on plan assets was 7.39%, 6.00% and 8.00%, respectively, based on the investment mix of our pension asset portfolio, historical asset performance and expectations for future performance. During fiscal 2007, lump sum benefit payments of $10.8 million exceeded the combined service and interest costs of the net periodic pension cost. As a result, we recorded a non-cash settlement charge of $3.3 million in order to accelerate recognition of a portion of cumulative unrecognized losses in the defined benefit pension plan. These unrecognized losses were previously accumulated as a reduction to partners’ capital and were being amortized to expense as part of our net periodic pension cost. During fiscal 2009 and fiscal 2008, 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 2009 or fiscal 2008. Additional pension settlement charges may be required in future periods depending on the level of lump sum benefit payments made in future periods. 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 26, 2009. (Dollars in thousands) Fiscal 2010 Fiscal 2011 Fiscal 2012 Fiscal 2013 Fiscal 2014 Long-term debt obligations Future interest payments Operating lease obligations (a) Self-insurance obligations (b) Other contractual obligations Total - $ 25,838 14,297 12,995 24,210 77,340 $ $ - 25,058 11,461 10,239 18,278 65,036 $ $ - 25,058 8,643 7,474 17,288 58,463 $ $ 100,000 25,058 6,791 5,021 14,005 150,875 $ $ 250,000 8,594 5,522 3,054 14,508 281,678 $ Fiscal 2015 and thereafter - $ - 4,223 13,465 64,115 81,803 $ (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 46 recovered from our insurance providers, which was $14.8 million as of September 26, 2009 and included in other assets on the consolidated balance sheet. Additionally, we have standby letters of credit in the aggregate amount of $57.2 million, in support of retention levels under our casualty insurance programs and certain lease obligations, which expire periodically through April 15, 2010. Operating Leases We lease certain property, plant and equipment for various periods under noncancelable operating leases, including approximately 55% of our vehicle fleet, approximately 25% of our customer service centers and portions of our information systems equipment. Rental expense under operating leases was $17.3 million, $17.7 million and $19.6 million for fiscal 2009, 2008 and 2007, respectively. Future minimum rental commitments under noncancelable operating lease agreements as of September 26, 2009 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 2016, 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 $18.3 million. The fair value of residual value guarantees for outstanding operating leases was de minimis as of September 26, 2009 and September 27, 2008. Recently Issued Accounting Standards In December 2008, the Financial Accounting Standards Board (“FASB”) issued new financial reporting guidance to require more detailed disclosures about employers' pension plan assets. These new disclosures will include more information on investment strategies, major categories of plan assets, concentrations of risk within plan assets and valuation techniques used to measure the fair value of plan assets. The new guidance is effective for fiscal years ending after December 15, 2009, which will be our 2010 fiscal year ending September 25, 2010. Since it only addresses disclosures, the adoption of the new guidance is not expected to have an impact on our consolidated financial position, results of operations and cash flows. In December 2007, the FASB issued revised accounting guidance concerning business combinations. Among other things, this revised guidance requires an entity to recognize acquired assets, liabilities assumed and any noncontrolling interest at their respective fair values as of the acquisition date, clarifies how goodwill involved in a business combination is to be recognized and measured, as well as requires the expensing of acquisition-related costs as incurred. Most of its provisions are effective for business combinations entered into in fiscal years beginning on or after December 15, 2008, which will be our 2010 fiscal year beginning September 27, 2009, with early adoption prohibited. Certain provisions, in particular a provision related to the accounting for acquired tax benefits, are required to be applied in future fiscal years regardless of when the business combination occurred. To the extent our Corporate Entities generate taxable profits in future years that enable the utilization of tax benefits acquired in the Agway Energy acquisition, the corresponding reduction in the valuation allowance will be recorded as a reduction in the provision for income taxes. 47 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, availability of supply, and demand for a given time of the year. Typically, our on hand priced position does not exceed more than four to eight weeks of our supply needs, depending on the time of the year. In the course of normal operations, we routinely enter into contracts such as forward priced physical contracts for the purchase or sale of propane and fuel oil that, under 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, forward contracts and, in certain instances, over-the-counter option contracts (collectively, “derivative instruments”) to manage the price risk associated with priced, physical product and with future purchases of the commodities used in our operations, principally propane and fuel oil, as well as to ensure the availability of product during periods of high demand. We do not use derivative instruments for speculative or trading purposes. Futures and forward contracts require that we sell or acquire propane or fuel oil at a fixed price for delivery at fixed future dates. An option contract allows, but does not require, its holder to buy or sell propane or fuel oil at a specified price during a specified time period. However, the writer of an option contract must fulfill the obligation of the option contract, should the holder choose to exercise the option. At expiration, the contracts are settled by the delivery of the product to the respective party or are settled by the payment of a net amount equal to the difference between the then current price and the fixed contract price or option exercise price. To the extent that we utilize derivative instruments to manage exposure to commodity price risk and commodity prices move adversely in relation to the contracts, we could suffer losses on those derivative instruments when settled. Conversely, if prices move favorably, we could realize gains. Under our hedging and risk management strategy, realized gains or losses on derivative instruments will typically offset losses or gains on the physical inventory once the product is sold to customers at market prices. Market Risk We are subject to commodity price risk to the extent that propane or fuel oil market prices deviate from fixed contract settlement amounts. Futures traded with brokers of the NYMEX require daily cash settlements in margin accounts. Forward and option contracts are generally settled at the expiration of the contract term either by physical delivery or through a net settlement mechanism. Market risks associated with futures, options and forward contracts are monitored daily for compliance with our Hedging and Risk Management Policy which includes volume limits for open positions. Open inventory positions are reviewed and managed daily as to exposures to changing market prices. 48 Credit Risk Futures and fuel oil options are guaranteed by the NYMEX and, as a result, have minimal credit risk. We are subject to credit risk with over-the-counter forward and propane option contracts to the extent the counterparties do not perform. We evaluate the financial condition of each counterparty with which we conduct business and establish credit limits to reduce exposure to the risk of non-performance by our counterparties. Interest Rate Risk A portion of our 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 ½ 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 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 26, 2009, the fair value of the interest rate swaps was $4.2 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 cost of products sold during the same period in which the hedged item affects earnings. The mark-to-market gains or losses on ineffective portions of cash flow hedges are immediately recognized in cost of products sold. Changes in the fair value of derivative instruments that are not designated as cash flow hedges, and that do not meet the normal purchase and normal sale exemption, are recorded within cost of products sold as they occur. Cash flows associated with derivative instruments are reported as operating activities within the consolidated statement of cash flows. At September 26, 2009, the fair value of derivative instruments described above resulted in current derivative assets (unrealized gains) of $9.2 million included within other current assets, non-current derivative assets of $0.5 million included within other assets, $4.8 million of derivative liabilities (unrealized losses) included within other current liabilities and non-current derivative liabilities of $0.2 million included within other liabilities. Cost of products sold included unrealized (non-cash) gains of $1.7 million and $1.8 million for the years ended September 26, 2009 and September 27, 2008, respectively, attributable to the change in fair value of derivative instruments not designated as cash flow hedges. Our outstanding commodity-related derivatives mature between fiscal 2010 and fiscal 2011, and have a weighted average maturity of approximately 7 months as of September 26, 2009. 49 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: A. The fair value of open positions as of September 26, 2009 for each of the future periods. B. The estimated forward market prices as of September 26, 2009 as derived from the NYMEX for traded commodities for each of the future periods. C. The market prices determined in B. above were adjusted adversely by a hypothetical 10% change in the forward prices 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 each of the future months for which a future or option contract exists indicates a reduction in potential future net gains of $2.5 million as of September 26, 2009. 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. 50 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 Fiscal 2009 Revenues Cost of products sold Income (loss) before interest expense, loss on debt extinguishment and provision for income taxes (a) Loss on debt extinguishment (b) Net income (loss) (a) Net income (loss) per common unit - basic (d) Net income (loss) per common unit - diluted (d) Cash provided by (used in) Operating activities Investing activities Financing activities EBITDA (e) Adjusted EBITDA (e) Retail gallons sold Propane Fuel oil and refined fuels First Quarter Second Quarter Third Quarter Fourth Quarter Total Year $ 363,315 174,230 $ 445,225 208,259 $ 184,372 87,463 $ 150,242 70,433 $ 1,143,154 540,385 90,229 - 80,688 2.46 2.45 125,194 - 114,866 3.50 3.48 3,793 - (7,435) (0.23) (0.23) (8,601) (4,624) (22,881) (0.67) (0.67) 210,615 (4,624) 165,238 4.99 4.96 25,004 (3,724) (28,390) 97,252 82,246 $ $ 133,948 (2,515) (26,564) 132,325 142,015 $ $ 64,546 (3,632) (40,272) 11,506 17,654 $ $ 23,053 (6,981) (108,998) $ (4,749) $ (7,294) 246,551 (16,852) (204,224) 236,334 234,621 $ $ 99,047 16,716 134,512 24,125 61,212 9,677 49,123 6,863 343,894 57,381 Fiscal 2008 Revenues Cost of products sold Income (loss) before interest expense and provision for income taxes (a) Income (loss) from continuing operations (a) Discontinued operations: Gain on disposal of discontinued operations (c) Net income (loss) (a) Net income (loss) from continuing operations per common unit - basic (d) Net income (loss) per common unit - basic (d) Net income (loss) per common unit - diluted (d) $ 425,109 277,715 $ 587,097 380,757 $ 305,476 212,974 $ 256,481 167,990 1,574,163 $ 1,039,436 51,789 41,722 43,707 85,429 1.27 2.61 2.60 104,375 94,523 (4,380) (13,747) (1,656) (11,325) - 94,523 - (13,747) - (11,325) 2.89 2.89 2.87 (0.42) (0.42) (0.42) (0.35) (0.35) (0.35) 150,128 111,173 43,707 154,880 3.39 4.72 4.70 Cash (used in) provided by Operating activities Investing activities Financing activities EBITDA (e) Adjusted EBITDA (e) Retail gallons sold Propane Fuel oil and refined fuels (41,953) 48,875 (24,539) 102,555 105,238 $ $ 50,340 (3,553) (24,953) 111,482 113,817 $ $ 48,601 (5,419) (25,362) 2,779 (1,916) $ $ 63,529 (3,273) (41,181) 5,413 3,326 $ $ 120,517 36,630 (116,035) 222,229 220,465 $ $ 111,937 23,594 146,252 31,435 71,420 12,614 56,613 8,872 386,222 76,515 51  Due to the seasonality of the retail propane business, our first and second quarter revenues and earnings are consistently greater than third and fourth quarter results. The following presents our selected quarterly financial data for the last two fiscal years (unaudited; in thousands, except per unit amounts). (a) These amounts include gains from the disposal of property, plant and equipment of $0.7 million for fiscal 2009 and $2.3 million for fiscal 2008. (b) During the fourth quarter of fiscal 2009, we purchased $175.0 million aggregate principal amount of the 2003 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. (c) Gain on disposal of discontinued operations reflects a $43.7 million gain on the Tirzah Sale during the first quarter of fiscal 2008 for net cash proceeds of $53.7 million. These gains were accounted for within discontinued operations. (d) Basic net income (loss) per Common Unit is computed under 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. Diluted net income per Common Unit is computed by dividing net income (loss) by the weighted average number of outstanding Common Units and unvested restricted units granted under our Restricted Unit Plans. (e) EBITDA represents net income before deducting interest expense, income taxes, depreciation and amortization. Adjusted EBITDA represents EBITDA excluding the unrealized net gain or loss on mark-to- market activity for derivative instruments. 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 GAAP and should not be considered as an alternative to net income or net cash provided by operating activities determined in accordance with GAAP. Because EBITDA 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 (amounts in thousands): 52 Fiscal 2009 Net income (loss) Add: Provision for income taxes Interest expense, net Depreciation and amortization EBITDA Unrealized (non-cash) (gains) losses on changes in fair value of derivatives Adjusted EBITDA Add (subtract): Provision for income taxes - current Interest expense, net Loss on debt extinguishment Unrealized (non-cash) gains (losses) on changes in fair value of derivatives Compensation cost recognized under Restricted Unit Plan (Gain) loss on disposal of property, plant and equipment, net Changes in working capital and other assets and liabilities First Quarter Second Quarter Third Quarter Fourth Quarter Total Year $ 80,688 $ 114,866 $ (7,435) $ (22,881) $ 165,238 138 9,403 7,023 97,252 (15,006) 82,246 (138) (9,403) - 886 9,442 7,131 132,325 9,690 142,015 1,160 10,068 7,713 11,506 6,148 17,654 (426) (9,442) - (240) (10,068) - 302 9,354 8,476 (4,749) (2,545) (7,294) (297) (9,354) 4,624 15,006 (9,690) (6,148) 2,545 569 672 644 (230) (393) (147) 511 120 2,486 38,267 30,343 236,334 (1,713) 234,621 (1,101) (38,267) 4,624 1,713 2,396 (650) (63,046) 11,212 62,851 32,198 43,215 Net cash provided by operating activities $ 25,004 $ 133,948 $ 64,546 $ 23,053 $ 246,551 Fiscal 2008 Net income (loss) Add: First Quarter Second Quarter Third Quarter Fourth Quarter Total Year $ 85,429 $ 94,523 $ (13,747) $ (11,325) $ 154,880 Provision for (benefit from) income taxes Interest expense, net Depreciation and amortization EBITDA Unrealized (non-cash) losses (gains) on changes in fair value of derivatives Adjusted EBITDA Add (subtract): (Provision for) benefit from income taxes - current Interest expense, net Unrealized (non-cash) (gains) losses on changes in fair value of derivatives Compensation cost recognized under Restricted Unit Plan Gain on disposal of property, plant and equipment, net Gain on disposal of discontinued operations Changes in working capital and other assets and liabilities 1,679 8,388 7,059 102,555 2,683 105,238 434 9,418 7,107 111,482 2,335 113,817 (402) (8,388) (190) (9,418) (157) 9,524 7,159 2,779 (4,695) (1,916) (87) (9,524) (53) 9,722 7,069 5,413 (2,087) 3,326 53 (9,722) (2,683) (2,335) 4,695 2,087 (67) (1,429) (43,707) 753 (283) - 817 (109) - 653 (431) - 1,903 37,052 28,394 222,229 (1,764) 220,465 (626) (37,052) 1,764 2,156 (2,252) (43,707) (90,515) (52,004) 54,725 67,563 (20,231) Net cash (used in) provided by operating activities $ (41,953) $ 50,340 $ 48,601 $ 63,529 $ 120,517 53 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 26, 2009. 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 26, 2009. 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 26, 2009, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. Management’s Report on Internal Control over Financial Reporting is included below. In the ordinary course of business, we review our system of internal control over financial reporting and make changes to our systems and processes to improve controls and increase efficiency, while ensuring that we maintain an effective internal control environment. Changes may include such activities as implementing new, more efficient systems and automating manual processes. MANAGEMENT'S REPORT ON 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. INTERNAL CONTROL OVER FINANCIAL REPORTING. 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 26, 2009. 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. 54 Based on the Partnership’s assessment, as described above, management has concluded that, as of September 26, 2009, the Partnership’s internal control over financial reporting was effective. Our independent registered public accounting firm, PricewaterhouseCoopers LLP, issued an attestation report dated November 25, 2009 on the effectiveness of our internal control over financial reporting, which is included herein. ITEM 9B. OTHER INFORMATION None. 55 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 Common Unitholders for three-year terms. Most recently, all six current Supervisors were elected to three-year terms at the Tri-Annual Meeting held on July 22, 2009 (see Item 4 above). 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 audit committee financial experts and are independent within the meaning of the NYSE corporate governance listing standards and in accordance with Rule 10A-3 of the Exchange Act, Item 407 of Regulation S-K and the Partnership’s criteria for Supervisor independence (as discussed in Item 13, herein) as of the date of this Annual Report. Mr. 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. 56 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, 2009. 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 Michael J. Dunn, Jr. ………………. 60 Michael A. Stivala………………… 40 Michael M. Keating……………….. 56 45 A. Davin D’Ambrosio…………….. 56 Paul Abel…………………………. 52 Mark Anton, II……………………. 45 Steven C. Boyd…………………… 48 Douglas T. Brinkworth…………… 44 Neil Scanlon………………………. Mark Wienberg…………………… 47 39 Michael Kuglin…………………… Harold R. Logan, Jr. ……………… 65 79 John Hoyt Stookey….…………….. Dudley C. Mecum………………… John D. Collins…………………… 74 71 Jane Swift………………………… 44 Position With the Partnership President and Chief Executive Officer; Member of the Board of Supervisors Chief Financial Officer Senior Vice President - Administration Vice President and Treasurer Vice President, General Counsel and Secretary Vice President – Business Development Vice President – Field Operations Vice President – Product Supply Vice President – Information Services Vice President – Operational Support and Analysis Controller and Chief Accounting Officer Member of the Board of Supervisors (Chairman) Member of the Board of Supervisors (Chairman of the Compensation Committee) Member of the Board of Supervisors Member of the Board of Supervisors (Chairman of the Audit Committee) Member of the Board of Supervisors In accordance with a management succession plan developed by the Compensation Committee of the Partnership’s Board of Supervisors and Mark Alexander, our Chief Executive Officer, Mr. Alexander stepped down from his position as Chief Executive Officer of the Partnership at the conclusion of fiscal 2009. At that time, Michael J. Dunn, Jr., our President, assumed the additional role of Chief Executive Officer effective September 27, 2009 (the beginning of our fiscal 2010). 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. 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. 57 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 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. 58 Logan served as Senior Vice President of Finance and a Director of Associated Natural Gas Corporation, an independent gatherer and marketer of natural gas, natural gas liquids and crude oil. Mr. Logan is also a Director of Graphic Packaging Holding Company, Hart Energy Publishing LLP and Cimarex Energy Co. 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. Mecum has served as a Supervisor since June 1996. He has been a Managing Director of Capricorn Holdings, LLC (a sponsor of and investor in leveraged buyouts) since June 1997. Mr. Mecum was a partner of G.L. Ohrstrom & Co. (a sponsor of and investor in leveraged buyouts) from 1989 to June 1996. Mr. Collins has served as a Supervisor since April 2007. He served with KPMG, LLP, an international accounting firm, from 1962 until 2000, most recently as senior audit partner of its New York office. He has served as a United States representative on the International Auditing Procedures Committee, a committee of international accountants responsible for establishing international auditing standards. Mr. Collins is a Director of Montpelier Re, Mrs. Fields Original Cookies, Inc. and Columbia Atlantic Funds, and serves as a Trustee of LeMoyne College. Ms. Swift has served as a Supervisor since April 2007. She is the founder of WNP Consulting, LLC, providing expert advice and guidance to early stage education companies. From 2003 to 2006 she was a General Partner at Arcadia Partners, a venture capital firm focused on the education industry. She currently serves on the boards of K12, Inc., Animated Speech Company and Sally Ride Science Inc. and several not-for-profit boards, including The Republican Majority for Choice and Landmark Volunteers, Inc. Prior to joining Arcadia, Ms. Swift served for 15 years in Massachusetts state government, becoming Massachusetts’ first woman governor in 2001. Section 16(a) Beneficial Ownership Reporting Compliance Section 16(a) of the Exchange Act requires our Supervisors, executive officers and holders of ten percent or more of our Common Units to file initial reports of ownership and reports of changes in ownership of our Common Units with the SEC. Supervisors, executive officers and ten percent Unitholders are required to furnish the Partnership with copies of all Section 16(a) forms that they file. Based on a review of these filings, we believe that all such filings were timely made during fiscal 2009. 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. 59 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. Our then current Chief Executive Officer submitted his Annual CEO Certification for 2009 to the NYSE without qualification. 60 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 Chief Executive Officer, the President, the Chief Financial Officer and the other three most highly compensated executive officers. In accordance with a management succession plan developed by the Compensation Committee of the Partnership’s Board of Supervisors and Mark Alexander, our Chief Executive Officer, Mr. Alexander stepped down from his position as Chief Executive Officer of the Partnership at the conclusion of fiscal 2009. At that time, Michael J. Dunn, Jr., our President, assumed the additional role of Chief Executive Officer effective September 27, 2009 (the beginning of our fiscal 2010). 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 • Discretionary 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 because it permits them to share in benefits generated in the future; 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 61 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 was provided with benchmarking data for a relevant peer group of companies for comparison purposes. The benchmarking data is just one of a number of factors considered by the Committee, but is not necessarily the most persuasive factor. The benchmarking data used in determining compensation for the 2009 fiscal year was derived from the Mercer Human Resource Consulting, Inc. (“Mercer”) Benchmark Database containing information obtained from surveys of over 2,500 organizations and approximately 200 positions which may include similarly-sized national propane marketers. The Committee does not base its benchmarking solely on a peer group of other propane marketers. The use of the Mercer database provides a broad base of compensation benchmarking information for companies of a similar size to Suburban. The peer group used for the Suburban positions consisted of organizations included in the Mercer database that report median annual revenues of between $1.0 billion and $4 billion per year. The Committee believes that benchmarking against such companies in determining “total cash compensation opportunities” is appropriate because of the proximity of the Partnership’s headquarters to New York City and the need to realistically compete for skilled executives in an environment shared by numerous other enterprises that seek skilled employees. For this reason, the Committee chooses not to base its benchmarking on the compensation practices of other propane marketers due to the fact that the other, similarly-sized propane marketers compete for employees in vastly different economic environments. Alternatively, for the reasons below, the Committee decided to include all other propane marketers, structured as publicly traded partnerships, in the peer group it selected for the 2003 Long-Term Incentive Plan (for more on the 2003 Long-Term Incentive Plan, refer to the subheading “2003 Long-Term Incentive Plan” below). Earning a payment under the 2003 Long-Term Incentive Plan is dependent upon the performance (referred to in the plan document as “total return to unitholders”) of our Common Units in comparison to the unit performance of a peer group of eleven other master limited partnerships over a three-year measurement period. Because total return to unitholders is based on unit price appreciation and distributions, both of which are impacted by earnings, this plan was implemented by the Committee to provide an incentive to management to grow the business and to be conservative in regard to the management of expenses, among other things, and, thereby, enhance the return that we provide to our investors. Because master limited partnerships are not taxpaying entities, potentially these entities have more available cash to distribute to their investors than similar businesses that operate as corporations and do pay corporate-level taxes. This sometimes enables master limited partnerships to provide a greater return, in the form of cash distributions, to their investors than similarly situated corporations. As a result of this reasoning, the Committee selected a peer group for the 2003 Long-Term Incentive Plan that included other propane marketers. In establishing the fiscal 2007 executive compensation packages, the Committee used the median total compensation paid by the peer group to assess whether the “total cash compensation opportunities” that we provide to our executive officers are both competitive and commensurate with each executive officer’s position and corresponding duties. However, in establishing the executive compensation packages for subsequent fiscal years, due to the Committee’s perception of the competitiveness of executive compensation packages provided to 62 executives in the New York area, the Committee used the mean of the reported data as its benchmark. Generally speaking, the mean of the reported data is higher than the median. In recent fiscal years, the members of the Committee have focused on lessening the shortfalls between the compensation packages that we provide to our executive officers and the mean compensation paid by the companies whose data underlie the Mercer database. The Committee does not, however, have a formal target with respect to the amount of the shortfall it is trying to lessen. Moreover, the Committee does not set specific percentile targets for total compensation of our executive officers compared to the total compensation of the peer group. In making their decisions regarding our fiscal 2009 executive compensation packages, during the Committee’s November 13, 2008 meeting, the members of the Committee reviewed the total cash compensation opportunities that we provided to our executive officers during fiscal 2008. Each executive officer’s “total cash compensation opportunities” consist of base salary, an annual cash bonus, and 2003 Long-Term Incentive Plan awards. The Committee then compared each executive officer’s total cash compensation opportunity to the total mean cash compensation opportunity for the parallel position in the Mercer study. By focusing on each executive officer’s total cash compensation opportunities as a whole, instead of on single components of compensation such as base salary, the Committee created fiscal 2009 compensation packages for our executive officers that emphasize the performance-based components of compensation. The Committee also met on July 22, 2009 to consider salary increases for seven of our executive officers (four of whom are among our named executive officers) who assumed additional responsibilities as a result of the administrative reorganization that occurred following our April 23, 2009 announcement that Mr. Dunn would succeed Mr. Alexander as our Chief Executive Officer (while, at the same time, remaining as our President). Mr. Dunn received a base salary increase (from $425,000 to $475,000) in recognition of his assumption of the additional responsibilities of Chief Executive Officer; Mr. Stivala, our Chief Financial Officer, received a base salary increase (from $260,000 to $275,000) in recognition of his assumption of responsibility for our Information Services Department; Mr. Keating, our former Vice President of Human Resources, received a base salary increase (from $225,000 to $260,000), an increased cash bonus percentage (from 65% to 70%) and was promoted to Senior Vice President of Administration in recognition of his assumption of administrative responsibilities for the entire enterprise; and Mr. Brinkworth, our Vice President of Product Supply, received a base salary increase (from $225,000 to $245,000) in recognition of his assumption of responsibility for our Non- Fuel Purchasing Department. These base salary increases and Mr. Keating’s promotion became effective on August 1, 2009. Although the cash incentives under our annual cash bonus plan and our Long-term Incentive Plan awards bear a formulaic relationship to base salary, all fiscal 2009 cash incentive payments and Long-term Incentive Plan awards for these seven executive officers were based upon the base salaries (and, in Mr. Keating’s case, bonus percentage) approved by the Committee at its November 13, 2008 meeting. In anticipation of their July 22, 2009 meeting, the members of the Committee conducted reviews that were similar to those conducted in anticipation of their November 13, 2008 meeting. The Committee indicated that it will not consider base salary increases for the seven executive officers who received base salary increases at its July 22, 2009 meeting until fiscal 2011 (unless unforeseen circumstances arise that require special consideration). Role of Executive Officers and Compensation Committee in Compensation Process The Committee establishes and enforces our general compensation philosophy in consultation with our Chief Executive Officer. The role of our Chief Executive Officer in the executive compensation process is to recommend individual pay adjustments for the executive officers, other than himself, to the Committee based on market conditions, our performance, and individual performance. With the assistance of our Senior Vice President of Administration, our Chief Executive Officer presents the Committee with information comparing each executive officer’s compensation to the mean compensation figures provided in the Mercer database. 63 The Partnership’s sole use of Mercer was to provide the Committee with benchmarking data. Therefore, neither our Chief Executive Officer nor our President met with representatives from Mercer. The information provided by Mercer was derived from a proprietary database maintained by Mercer and, as such, there was no formal consultancy role played by them. The Committee believes that the Mercer benchmarking data, which is provided to the Committee by our 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 Chief Executive Officer, President, Chief Financial Officer and our other executive officers; • Reporting to the Board of Supervisors any and all decisions regarding compensation changes for our Chief Executive Officer, President, Chief Financial Officer and our other executive officers; • Evaluating and approving our annual cash bonus plan, long-term incentive plan, restricted unit plan, as well as all other compensation policies and programs; • Administering and interpreting the compensation plans that constitute each component of our executive officers’ compensation packages; and • Engaging consultants, when appropriate, to provide independent, third-party advice on executive officer-related compensation. 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 tables summarize the components as percentages of each named executive officer’s total cash compensation opportunity in fiscal 2009 (as determined at the Committee’s November 13, 2008 and July 22, 2009 meetings, respectively). November 13, 2008 Meeting Base Salary Cash Bonus Target Long-Term Incentive Mark A. Alexander(1) Michael A. Stivala Michael J. Dunn, Jr. Steven C. Boyd Michael M. Keating Douglas T. Brinkworth 43% 47% 40% 47% 50% 47% 43% 35% 40% 35% 33% 35% 14% 18% 20% 18% 17% 18% (1) Mr. Alexander’s Long-Term Incentive Plan award was established per the terms of an agreement between Mr. Alexander and the Partnership. July 22, 2009 Meeting Base Salary Cash Bonus Target Long-Term Incentive Michael A. Stivala Michael J. Dunn, Jr. Michael M. Keating Douglas T. Brinkworth 47% 40% 48% 45% 35% 40% 34% 36% 18% 20% 18% 19% 64 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 and the 2003 Long-Term Incentive Plan (see below for a description of these plans). The fiscal 2007, fiscal 2008 and fiscal 2009 compensation packages for our Chief Executive Officer and our President were set forth in their respective employment agreements, as further described below. As a result, different weight may be given to different components of compensation among each of our named executive officers. In addition, as discussed in the section above titled “Allocation Among Components,” the compensation packages that we provide to our senior-most levels of management are, at a minimum, 50% performance-based. In order to align the interests of senior management with the interests of our Common Unitholders, we consider it requisite to accentuate the performance-based elements of the compensation packages that we provide to these individuals because the actions and decisions of these individuals have a direct impact on our performance. Base Salary Base salaries for the named executive officers and, indeed, all of our other executive officers, are reviewed and approved annually by the Committee. In order to determine the fiscal 2009 base salary increases, the Committee compared each executive officer’s fiscal 2008 base salary with the corresponding mean salary provided in the Mercer database. The Committee determined base salary adjustments, which may be higher or lower than the comparative data, following an assessment of our overall results as well as each executive officer’s position, performance and scope of responsibility, while at the same time considering each executive officer’s previous total cash compensation opportunities. At the beginning of fiscal 2009, each named executive officer received adjustments to his base salary in accordance with the philosophy and process described above, ranging from 0% to 6%. In the event of a promotion, a significant increase in an executive officer’s responsibilities, or a new hire, the Committee reviews and takes action at its next meeting as it did at its July 22, 2009 meeting. The fiscal 2009 adjustments to each named executive officer’s base salary were as follows: November 13, 2008 July 22, 2009 Mark A. Alexander Michael A. Stivala Michael J. Dunn, Jr Steven C. Boyd Michael M. Keating Douglas T. Brinkworth 0%(1) 4% 0%(1) 6% 2% 5% n/a 6% (2) 12% (3) n/a 16% (4) 9% (5) (1) Because Mr. Alexander’s and Mr. Dunn’s base salaries were set forth under the provisions of their respective employment agreements, the Committee did not adjust their base salaries on November 13, 2008. 65 (2) The Committee’s July 22, 2009 decision to increase Mr. Stivala’s salary by 6% was based on consideration of his assuming responsibility for our Information Services Department. (3) The Committee’s July 22, 2009 decision to increase Mr. Dunn’s salary by 12% was based on consideration of his assuming the additional responsibilities as Chief Executive Officer, in addition to those of President. (4) The Committee’s July 22, 2009 decision to increase Mr. Keating’s salary by 16% was based on consideration of his assuming the increased responsibilities of Senior Vice President of Administration. (5) The Committee’s July 22, 2009 decision to increase Mr. Brinkworth’s salary by 9% was based on consideration of his assuming responsibility for our Non-Fuel Purchasing Department. The total base salary paid to each named executive officer in fiscal 2009 is reported in the column titled “Salary ($)” in the Summary Compensation Table below. Annual Cash Bonus Plan Annual cash bonuses (which fall within the SEC’s definition of “Non-Equity Incentive Plan Compensation” for the purposes of the Summary Compensation Table and otherwise) are earned by our executive officers in accordance with the performance objective provisions of our annual cash bonus plan. The cash bonuses earned by Mr. Alexander and Mr. Dunn are the only exceptions to this general rule because their bonus provisions are established in their respective employment agreements. Mr. Alexander’s employment agreement, which was superseded by his separation and consulting agreement (for more information on Mr. Alexander’s separation and consulting agreement, please refer to the section titled “Employment Agreements” below), provided for a maximum annual cash bonus equal to his base salary whereas Mr. Dunn’s employment agreement provides for a maximum annual cash bonus equal to 110% of his base salary. During fiscal 2007, in recognition of performance, the Committee provided Mr. Alexander with a cash bonus payment of 110% of his base salary to parallel the cash bonuses earned by the other named executive officers under our annual cash bonus plan. During fiscal 2009, as part of the negotiated terms of Mr. Alexander’s separation and consulting agreement, the Committee agreed to provide Mr. Alexander with a cash bonus payment of up to 110% of his base salary to parallel the cash bonuses earned by the other named executive officers under our annual cash bonus plan. Mr. Dunn has agreed with the Partnership to terminate his employment agreement effective as of the start of fiscal 2010; hereafter, Mr. Dunn’s annual cash bonus will, like those of the other executive officers, be governed by the terms of our annual cash bonus plan. Although our annual cash bonus plan is generally administered using the formula described below, occasionally the Committee may exercise its broad discretionary powers to decrease or increase the annual cash bonus paid to a particular executive officer when the Committee recognizes that a particular executive officer’s performance warrants a decreased or an increased bonus. Such adjustments, if any, are recommended to the Committee by our Chief Executive Officer. During fiscal 2009, our Chief Executive Officer did not make any such recommendations to the Committee. The terms of our annual cash bonus plan provide for cash payments of a specified percentage (which, in fiscal 2009 ranged from 65% to 100%) of our named executive officers’ annual base salaries (“target cash bonus”) if, for the fiscal year, actual EBITDA (as defined in Item 6, herein) equals the Partnership’s budgeted EBITDA. For purposes of calculating the annual cash bonus, the Committee may exercise discretion to adjust both budgeted and actual EBITDA for various items considered to be non-recurring in nature; including, but not limited to, unrealized (non-cash) gains or losses on derivative instruments reported within cost of products sold in our statement of operations and gains or losses on the disposal of discontinued operations (“cash bonus plan EBITDA”). Executive officers have the opportunity to earn between 90% and 110% of their target cash bonuses, in accordance with the terms of the plan, paralleling the percentage of actual cash bonus plan EBITDA in relationship to budgeted cash bonus plan EBITDA ranging from 90% to 110%. Under the annual cash bonus plan, no bonuses are earned if actual cash bonus plan EBITDA is less than 90% of budgeted cash bonus plan EBITDA and cash bonuses cannot exceed 110% of the target cash bonus even if actual cash bonus plan EBITDA is more than 110% of budgeted cash bonus plan EBITDA. 66 For fiscal 2009, our budgeted cash bonus plan EBITDA was $187 million. Our actual cash bonus plan EBITDA was such that each of our executive officers earned 110% of his or her target cash bonus. The following table provides the fiscal 2009 budgeted cash bonus plan EBITDA targets that were established at the November 13, 2008 Compensation Committee meeting: Fiscal 2009 Budgeted Cash Bonus Plan EBITDA (in Millions) $205.7 $196.4 $187.0 (1) $177.7 $168.3 Target Bonus Percentage that would have been Earned if Actual Cash Bonus Plan EBITDA Equaled the Figure in the Previous Column 110% 105% 100% 95% 90% (1) Budgeted cash bonus plan EBITDA for fiscal 2009. The bonuses earned under the annual cash bonus plan by each of our named executive officers are reported in the column titled “Non-Equity Incentive Plan Compensation ($)” in the Summary Compensation Table below. The 2009 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 2009 are summarized as follows: 2009 Target Cash Bonus as a % of Base Salary Established by the Committee at its November 13, 2008 Meeting 100% 75% 100% 75% 65% 75% Name Mark A. Alexander(1) Michael A. Stivala(2) Michael J. Dunn, Jr.(1) Steven C. Boyd Michael M. Keating(3) Douglas T. Brinkworth(2) 2009 Target Cash Bonus 2009 Actual Cash Bonus Earned $450,000 $195,000 $425,000 $195,000 $146,250 $495,000 $214,500 $467,500 $214,500 $160,875 $168,750 $185,625 (1) Mr. Alexander’s and Mr. Dunn’s target cash bonuses were originally established by the terms of their respective employment agreements. However, for fiscal 2009, as part of the negotiated terms of Mr. Alexander’s separation and consulting agreement, the Committee agreed to provide Mr. Alexander with a cash bonus payment of up to 110% of his base salary to parallel the cash bonuses earned by the other named executive officers under our annual cash bonus plan. Although Mr. Dunn received a salary increase that was approved by the Committee at its July 22, 2009 meeting, Mr. Dunn’s fiscal 2009 cash bonus payment was based upon his previous salary. See “Employment Agreements” section below. (2) Mr. Stivala’s and Mr. Brinkworth’s cash bonus payments were based upon the salaries set for them by the Committee at its November 13, 2008 meeting. (3) Mr. Keating’s fiscal 2009 cash bonus payment was based upon the salary and target cash bonus percentage set for him by the Committee at its November 13, 2008 meeting. However, because of the action taken by the Committee at its July 22, 2009 meeting, for fiscal 2010 his target cash bonus percentage will be 70%. For purposes of establishing the cash bonus targets for fiscal 2009, the Committee reviewed and approved our fiscal 2009 budgeted cash bonus plan EBITDA at its meeting on November 13, 2008. The budgeted cash bonus plan EBITDA is developed annually using a bottom-up process factoring in reasonable growth targets 67 from the prior year performance, while at the same time attempting to reach a good balance between a target that is reasonably achievable, yet not assured. As described above, executive officers have the opportunity to earn between 90% and 110% of their target cash bonuses, paralleling the percentage of actual cash bonus plan EBITDA in relationship to budgeted cash bonus plan EBITDA ranging from 90% to 110%. Over the past three years, our actual cash bonus plan EBITDA was such that each of our executive officers earned 110%, 95%, and 110% of their respective target cash bonus for fiscal 2009, fiscal 2008, and fiscal 2007, respectively. 2003 Long-Term Incentive Plan At the beginning of fiscal 2003, we adopted the 2003 Long-Term Incentive Plan (“LTIP-2”), a phantom unit plan, as a principal component of our executive compensation program. While the annual cash bonus plan is a pay-for-performance plan that focuses on our short-term financial goals, LTIP-2 is designed to motivate our executive officers to focus on long-term financial goals. LTIP-2 measures the market performance of our Common Units on the basis of total return to our Unitholders (“TRU”) during a three-year measurement period commencing on the first day of the fiscal year in which an unvested award was granted and compares our TRU to the TRU of each of the other members of a predetermined peer group, consisting solely of other master limited partnerships, approved by the Committee. The predetermined peer group may vary from year-to-year, but for all current awards, includes AmeriGas Partners, L.P., Ferrellgas Partners, L.P. and Inergy, L.P. (the other propane master limited partnerships). Unvested awards are granted at the beginning of each fiscal year as a Committee- approved percentage of each executive officer’s salary. Cash payouts, if any, are earned and paid at the end of the three-year measurement period. LTIP-2 is designed to: • Align a portion of our executive officers’ compensation opportunities with the long-term goals of our Unitholders; • Provide long-term compensation opportunities consistent with market practice; • Reward long-term value creation; and • Provide a retention incentive for our executive officers and other key employees. At the beginning of the three-year measurement period, each executive officer’s unvested award of phantom units is calculated by dividing a predetermined percentage (which is 30% for Mr. Alexander and for all other executive officers is 52%), established upon adoption of LTIP-2, of the executive officer’s target cash bonus by the average of the closing prices of our Common Units for the twenty days preceding the beginning of the fiscal year. At the end of the three-year measurement period, depending on the quartile ranking within which our TRU falls relative to the other members of the peer group, our executive officers, as well as the other participants, all of whom are key employees, will receive a cash payout equal to: • The quantity of the participant’s phantom units multiplied by the average of the closing prices of our Common Units for the twenty days preceding the conclusion of the three-year measurement period; • The quantity of the participant’s phantom units multiplied by the sum of the distributions that would have inured to one of our outstanding Common Units during the three-year measurement period; and • The sum of the products of the two preceding calculations multiplied by: zero if our performance falls within the lowest quartile of the peer group; 50% if our performance falls within the second lowest quartile; 100% if our performance falls within the second highest quartile; and 125% if our performance falls within the top quartile. 68 The three-year measurement period of the fiscal 2007 award ended simultaneously with the conclusion of fiscal 2009. The TRU for the fiscal 2007 award fell within the highest quartile. The following is a summary of the cash payouts related to the fiscal 2007 award earned by our named executive officers at the conclusion of fiscal 2009. Mark A. Alexander Michael A. Stivala Michael J. Dunn, Jr. Steven C. Boyd Michael M. Keating Douglas T. Brinkworth $ 252,479(1) (2) $ 101,004(1) $ 389,020(1) $ 128,350(1) $ 132,761(1) $ 113,795(1) (1) The cash payouts related to our named executive officers’ fiscal 2007 awards earned at the conclusion of fiscal 2009 is an additional disclosure that bears no meaningful relationship to the expense recognized during fiscal 2009 and reported in column (e) of the Summary Compensation Table below. (2) Mr. Alexander’s payment is considerably smaller than Mr. Dunn’s as a result of an agreement between Mr. Alexander and the Partnership. The following is a summary of the quantity of phantom units that signify the unvested awards granted to our named executive officers during fiscal 2008 and fiscal 2009 that will be used to calculate cash payments at the end of each respective award’s three-year measurement period (i.e., at the end of fiscal 2010 for the fiscal 2008 award and at the end of fiscal 2011 for the fiscal 2009 award): Mark A. Alexander Michael A. Stivala Michael J. Dunn, Jr. Steven C. Boyd Michael M. Keating Douglas T. Brinkworth Fiscal 2008 Award 2,989 1,871 4,894 1,693 1,647 1,857 Fiscal 2009 Award 3,752 2,818 6,142 2,818 2,114 2,439 The peer group members selected by the Committee for the fiscal 2007, fiscal 2008 and fiscal 2009 awards consist entirely of publicly-traded partnerships, inclusive of all propane-related partnerships. The Committee decided upon this peer group because all publicly-traded partnerships have similar tax attributes and can, as a result, distribute more cash than similarly-sized corporations generating similar revenues. The following table lists, in alphabetical order, the names and ticker symbols of the peer group used to measure our performance during the fiscal 2007, fiscal 2008 and fiscal 2009 LTIP-2 awards’ three-year measurement periods: Fiscal 2007, Fiscal 2008 and Fiscal 2009 LTIP-2 Awards Peer Group Peer Group Member Name AmeriGas Partners, L.P. Copano Energy, LLC Crosstex Energy, L.P. Dorchester Minerals, L.P. Energy Transfer Partners, L.P. Ferrellgas Partners, L.P. Inergy, L.P. MarkWest Energy Partners, L.P. Plains All American Pipeline, L.P. Star Gas Partners, L.P. Sunoco Logistics Partners, L.P. Ticker Symbol APU CPNO XTEX DMLP ETP FGP NRGY MWE PAA SGU SXL Formerly, the LTIP-2 plan document contained a retirement provision that provided for the immediate termination of the three-year measurement period for all outstanding LTIP-2 awards held by a retirement-eligible 69 participant upon retirement. Under the former provisions, TRU was calculated as if the three-year measurement period for each outstanding award ended on the participant’s retirement date in order to determine whether a payment had been earned by the retiree. On January 24, 2008, the Committee amended the retirement provisions of the plan document to provide that a retirement-eligible participant’s outstanding awards vest as of the retirement-eligible date, but such awards remain subject to the same three-year measurement period for purposes of determining the eventual cash payout, if any, at the conclusion of the measurement period. Because the cash payments under the LTIP-2 are based on the value of our Common Units, compensation expense generated by this plan is recognized ratably over the plan’s three-year measurement period; however, in the case of awards held by retirement-eligible participants, compensation expense is recognized in full when the unvested award is granted to the participant. As a result, because Mr. Dunn and Mr. Keating are, in accordance with the plan’s retirement provisions retirement-eligible participants, the compensation expense for Mr. Dunn’s and for Mr. Keating’s unvested awards appear higher than the compensation charges related to unvested awards held by the other named executive officers, none of whom meet the plan document’s retirement criteria. Therefore, the disparity in LTIP-2 compensation-related expense between the named executive officers who are retirement-eligible participants and the named executive officers who are not is attributable to the accounting requirements for the timing of expense recognition rather than to a disparity in actual compensation. In addition, as part of the negotiated terms of Mr. Alexander’s separation and consulting agreement, Mr. Alexander’s outstanding awards under the LTIP-2 vest as of September 26, 2009, 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. As a result, it was necessary to recognize all remaining unrecognized expense attributable to his unvested fiscal 2008 and fiscal 2009 awards during fiscal 2009. All such charges to this year’s earnings relative to our named executive officers are reported in the column titled “Unit Awards ($)” in the Summary Compensation Table below. Restricted Unit Plans 2000 Restricted Unit Plan We adopted the 2000 Restricted Unit Plan (“RUP”) effective November 1, 2000. Upon adoption, this plan authorized the issuance of 487,805 Common Units to our executive officers, managers and other employees and to the members of our Board of Supervisors. On October 17, 2006, following approval by our Unitholders, we adopted amendments to the RUP which, among other things, increased the number of Common Units authorized for issuance under the RUP by 230,000 for a total of 717,805. At the conclusion of fiscal 2009, there remained 37,397 restricted units available 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 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 RUP document. Upon vesting, restricted units are automatically converted into our Common Units, with full voting rights and rights to receive distributions. The RUP document previously contained a retirement provision that provided for the immediate vesting of all unvested RUP awards held by a retiring participant who met all three of the following conditions on his or her retirement date: 1. The unvested RUP award has been held by the grantee for at least six months; 2. The RUP grantee is age 55 or older; and 3. The RUP grantee has worked for us or one of our predecessors for at least 10 years. 70 On October 31, 2007, in order to comply with the regulations promulgated under Internal Revenue Code (“IRC”) Section 409A, the Board of Supervisors amended the retirement provision to require a six-month delay between a retirement eligible RUP participant’s retirement date and the date on which unvested RUP awards vest. All RUP awards are made at the discretion of the Committee. Because individual circumstances differ, the Committee has not adopted a formulaic approach to making RUP awards. Awards are granted at the Committee’s discretion when the need arises. Although the reasons for granting an award can vary, the objective of granting an award to a recipient is twofold: to retain the services of the recipient over the five-year vesting period while, at the same time providing the type of motivation that further aligns the long-term interests of the recipient with the long-term interests of our Unitholders. The reasons for which the Committee 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 equity ownership by our executive officers and, prior to October 17, 2006, the level of equity representation through management’s ownership of the then General Partner. When the Committee decides to grant an equity award, it approves a dollar amount of equity compensation that it wants to provide to a particular employee. This dollar amount is then converted into a quantity of restricted units by dividing that dollar amount by the average of the closing prices of our Common Units for the twenty trading days preceding the grant date. The Committee generally makes these awards at their first meeting each year following the availability of the financial results for the prior fiscal year; however, occasionally the Committee grants awards at other times of the year, particularly when the need arises to grant awards because of promotions and new hires. Until October 17, 2007, the grant date for RUP awards usually coincided with the Committee’s approval date. However, on October 31, 2007, the Committee adopted a 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. 71 During fiscal 2009, RUP awards were granted to the following named executive officers: Grant Date Quantity of Restricted Units December 1, 2008 Michael A. Stivala December 1, 2008 Steven C. Boyd December 1, 2008 Michael M. Keating Douglas T. Brinkworth December 1, 2008 4,818 2,570 4,818 3,212 At its November 13, 2008 meeting, Mr. Stivala, Mr. Boyd, Mr. Keating and Mr. Brinkworth were the only named executive officers to whom the Committee granted RUP awards. All fiscal 2009 awards were made in recognition of the exemplary performance of each of the recipients and as retention tools. In determining the fiscal 2009 awards for Mr. Stivala, Mr. Boyd, Mr. Keating and Mr. Brinkworth, the Committee relied upon information provided by Mercer to conclude that these awards were necessary to remediate shortfalls perceived by the Committee in the cash compensation of these named executive officers. At its November 13, 2008 meeting, the Committee did not provide Mr. Alexander with a RUP award because, at the time, his compensation was dictated by the provisions of his employment agreement. The Committee chose not to provide Mr. Dunn with a fiscal 2009 award because his fiscal 2008 award was considerably higher than the quantities granted to the other recipients of fiscal 2008 awards due to the Committee’s desire to recognize his responsibilities as President and in consideration of his not having received any prior awards under the RUP. Because the Committee utilizes RUP awards as a retention tool and because at the time Mr. Dunn received his fiscal 2008 RUP award he satisfied the criteria found in the retirement provisions of the RUP document, the Committee exercised its discretionary authority to make his award subject to the special stipulation that he hold his unvested award for three years before the retirement provisions of the RUP document become applicable. At its November 10, 2009 meeting, the Committee concluded an extensive review of Mr. Dunn’s compensation relative to his assumption of additional responsibilities as the Partnership’s Chief Executive Officer at the commencement of fiscal 2010. Because the Committee believes that equity compensation is a critical component of executive compensation that helps to retain and motivate our executives, the Committee concluded, after comparing the cash components of Mr. Dunn’s compensation to the Mercer study, that it would be prudent to provide Mr. Dunn with a RUP award as of December 1, 2009, equal in value to $500,000, in recognition of his assuming the responsibilities of our Chief Executive Officer. This RUP award will be converted into a number of restricted units on the grant date using the formula set forth above. Generally, compensation expense for unvested RUP awards is recognized ratably over the vesting periods and is net of estimated forfeitures. However, when a RUP award is granted to a retirement-eligible individual, compensation expense associated with such award is recognized ratably over the six-month period following the grant date (because the RUP document requires that a retirement-eligible individual hold an unvested award for at least six months before the award becomes subject to the plan document’s retirement provisions). Although Mr. Dunn is a retirement-eligible participant, because the Committee stipulated that his fiscal 2008 award will not become subject to the RUP document’s retirement provisions until the conclusion of fiscal 2012, the compensation expense associated with Mr. Dunn’s fiscal 2008 award will be recognized ratably over the three- year period between the grant date and the conclusion of fiscal 2012. Because Mr. Keating is retirement-eligible participant whose fiscal 2009 award is subject to the normative retirement provisions of the RUP document, the timing of compensation expense recognition associated with his fiscal 2009 RUP award was recognized ratably over the six-month period following the grant date. As a result, all of the compensation expense associated with Mr. Keating’s fiscal 2009 RUP award was recognized during fiscal 2009 and, therefore, was greatly accelerated when contrasted to the recognition of compensation expense relative to the unvested RUP awards held by Mr. Stivala, Mr. Boyd and Mr. Brinkworth who do not meet the retirement criteria of the plan document. The RUP- related compensation expense recognized in the Partnership’s fiscal 2009 statement of operations, excluding forfeiture estimates, on behalf of each of the named executive officers is reported in the column titled “Unit Awards ($)” in the Summary Compensation Table below. 72 2009 Restricted Unit Plan At our July 22, 2009, Tri-Annual Meeting, our Unitholders approved our adoption of the 2009 Restricted Unit Plan (“RUP-2”) effective August 1, 2009. This plan was adopted because the 2000 Restricted Unit Plan, which terminates on October 31, 2010, had insufficient remaining units reserved for awards to meet our long term compensation needs. 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. At the conclusion of fiscal 2009, no awards had been granted under this plan. The provisions of this plan are substantially identical to those of the 2000 Restricted Unit Plan. Recoupment of Incentive Compensation On April 25, 2007, upon recommendation by the Committee, the Board of Supervisors approved an Incentive Compensation Recoupment Policy which permits the Committee to seek the reimbursement from certain executives of the Partnership and Operating Partnership of incentive compensation paid to those executives in connection with any fiscal year for which there is a significant restatement of the published financial statements of the Partnership triggered by a material accounting error, which results in less favorable results than those originally reported by the Partnership. Such reimbursement can be sought from executives even if they had no responsibility for the restatement. In addition to the foregoing, if the Committee determines that any fraud or intentional misconduct by an executive was a contributing factor to the Partnership having to make a significant restatement, then the Committee is authorized to take appropriate action against such executive, including disciplinary action, up to, and including, termination, and requiring reimbursement of all, or any part, of the compensation paid to that executive in excess of that executive’s base salary, including cancellation of any unvested restricted units. The Incentive Compensation Recoupment Policy is available on our website at www.suburbanpropane.com. On July 31, 2007, the Board amended the annual cash bonus plan, LTIP-2 and the RUP to expressly make future awards under such plans subject to the Incentive Compensation Recoupment Policy. RUP-2 was adopted with provisions that made it subject to the Incentive Compensation Recoupment Policy. Pension Plan We sponsor a noncontributory defined benefit pension plan that was originally designed to cover all of our eligible employees who met certain criteria relative to age and length of service. Effective January 1, 1998, we amended the plan in order to provide for a cash balance format rather than the final average pay format that was in effect prior to January 1, 1998. The cash balance format is designed to evenly spread the growth of a participant’s earned retirement benefit throughout his or her career rather than the final average pay format, under which a greater portion of a participant’s benefits were earned toward the latter stages of his or her career. Effective January 1, 2000, we amended the plan to limit participation in this plan to existing participants and no longer admit new participants to the plan. On January 1, 2003, we amended the plan to cease future service and pay-based credits on behalf of the participants and, from that point on, participants’ benefits have increased only due to interest credits. Each of our named executive officers, with the exception of Mr. Stivala, participates in the plan. The changes in the actuarial value relative to each named executive officer’s participation in the plan is reported in the column titled “Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)” in the Summary Compensation Table below. Deferred Compensation All employees, including the named executive officers, who satisfy certain service requirements, are entitled to participate in our IRC Section 401(k) Plan (the “401(k) Plan”), in which participants may defer a portion of 73 their eligible cash compensation up to the limits established by law. We offer the 401(k) Plan to attract and retain talented employees by providing them with a tax-advantaged opportunity to save for retirement. For fiscal 2009, all of our named executive officers participated in the 401(k) Plan. The benefits provided to our named executive officers under the 401(k) Plan are provided on the same basis as to our other exempt employees. Amounts deferred by our named executive officers under the 401(k) Plan are included in the column titled “Salary ($)” 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 Percentage of Budgeted EBITDA(1)… The Participating Employee Will Receive this Matching Contribution for the Year… 115% or higher 100% to 114% 90% to 99% Less than 90% 100% 50% 25% 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 2009, our budgeted 401(k) Plan EBITDA was $187.0 million. Our actual 401(k) Plan EBITDA fiscal 2009 results were such that each of our executive officers earned a matching contribution of 100%. As a result, we will provide participants with a match equal to 100% of their calendar year 2009 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. Non-Qualified Deferred Compensation Until January 2008, we maintained a Non-Qualified Deferred Compensation Plan (the “Compensation Deferral Plan”) to which vested restricted units from the 1996 Restricted Unit Plan (which was subsequently replaced by the 2000 Restricted Unit Plan described above) were deferred by the recipients, some of whom are our named executive officers, on May 26, 1999 in connection with our Recapitalization. The Compensation Deferral Plan operated through a rabbi trust, which held the deferred restricted units. On November 2, 2005, for the purpose of IRC Section 409A compliance, our Board of Supervisors approved an amendment to the Compensation Deferral Plan that prohibited any additional deferral elections. At the end of fiscal 2007, Mr. Alexander and Mr. Dunn were the only remaining beneficiaries of the Compensation Deferral Plan. In accordance with their deferral elections, the entire corpus of the rabbi trust was distributed to them during January 2008 and the fair market value of their respective portions of the corpus is included in their taxable wage earnings for calendar year 2008. Because the Compensation Deferral Plan contained only Common Units, and because the cash distributions that inured to those units were immediately distributed to the beneficiaries, the plan did not provide Mr. Alexander and Mr. Dunn with above market interest; nor did they receive distributions on the Common Units at a rate higher than the distributions paid on behalf of our Common Units held by the investing public. As a result, 74 nothing relative to the Compensation Deferral Plan is reported in the Summary Compensation Table below for fiscal 2009, fiscal 2008 or fiscal 2007. 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 Mr. Alexander and Mr. Dunn with a level of retirement income from us, without regard to statutory maximums, including the IRC’s limitation for defined benefit plans. In light of the conversion of the Pension Plan to a cash balance formula as described under the subheading “Pension Plan” above, the SERP was amended and restated effective January 1, 1998. The annual retirement benefit under the SERP represents the amount of annual benefits that the participants in the SERP would otherwise be eligible to receive, calculated using the same pay- based credits referenced in the “Pension Plan” section above, applied to the amount of annual compensation that exceeds the IRC’s statutory maximums for defined benefit plans, which was $200,000 in 2002. Effective January 1, 2003, the SERP was discontinued with a frozen benefit determined for Mr. Alexander and Mr. Dunn. When the SERP was adopted, prior to its being frozen, the plan was intended to provide Mr. Alexander with a monthly benefit of $6,737 and Mr. Dunn with a monthly benefit of $373 upon retirement. In accordance with the provisions of his separation and consulting agreement (for more information on Mr. Alexander’s separation and consulting agreement, please refer to the section titled “Employment Agreements” below), Mr. Alexander received a lump sum payment equal to what said lump sum payment would have been if Mr. Alexander had attained age 55 and retired on September 26, 2009. The amount of Mr. Alexander’s payment was $444,030. This amount was paid to Mr. Alexander during the thirty-day period following the conclusion of fiscal 2009. As a result of this payment to Mr. Alexander, Mr. Dunn is the plan’s sole remaining participant. Because Mr. Alexander was granted an additional four year’s interest credits (by September 26, 2009 he had attained age 51), he received above market interest credits. The above-market interest credits allocated to Mr. Alexander have been reported in the column titled “Change in Pension Value and Nonqualified Deferred Compensation Earnings” in the Summary Compensation Table below. During fiscal 2009, Mr. Dunn received no above-market interest credits relative to the SERP; therefore, nothing relative 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. In each case, with the exception of Mr. Alexander for whom we purchase supplemental life insurance and supplemental long- term disability policies at a cost of $6,556 per year, these benefits are provided on the same basis as are provided to other exempt employees. These benefit plans are offered to attract and retain talented employees by providing them with competitive benefits. Other than to Mr. Alexander, in accordance with the terms of his separation and consulting agreement that superseded his employment agreement (both of which are described below in the section titled “Employment Agreements”), and Mr. Dunn, in accordance with the terms of his employment agreement (described below in the section titled “Employment Agreements”), there are no post-termination or other special rights provided to any named executive officer to participate in these benefit programs other than the right to participate in such plans for a fixed period of time following termination of employment, on the same basis as is provided to other exempt employees, as required by law. As described below in the section titled “Employment Agreements,” Mr. Dunn has agreed with the Partnership to terminate his employment agreement effective as of the commencement of fiscal 2010. The costs of all such benefits incurred on behalf of our named executive officers are reported in the column titled “All Other Compensation ($)” in the Summary Compensation Table below. 75 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 2009. Name Mark A. Alexander Michael A. Stivala Michael J. Dunn, Jr. Steven C. Boyd Michael M. Keating Douglas T. Brinkworth Tax Preparation Services $3,500 $ -0- $3,000 $3,000 $3,000 $3,000 Employer- Provided Vehicle $11,819 $11,318 $12,205 $ 6,205 $11,015 $10,610 Physical $1,300 $1,300 $ -0- $ -0- $1,300 $ -0- Perquisite-related costs are reported in the column titled “All Other Compensation ($)” in the Summary Compensation Table below. Impact of Accounting and Tax Treatments of Executive Compensation As we are a partnership and not a corporation for federal income tax purposes, we are not subject to the limitations of IRC Section 162(m) with respect to tax deductible executive compensation. Accordingly, none of the compensation paid to our named executive officers is subject to a limitation as to tax deductibility. However, if such tax laws related to executive compensation change in the future, the Committee will consider the implications on us. In accordance with their respective employment agreements, Mr. Alexander and Mr. Dunn were entitled to receive tax gross-up payments for any parachute excise tax incurred pursuant to IRC Section 4999; they are also entitled to receive tax gross-up payments for any payment that violates the provisions of IRC Section 409A or its associated regulations. On November 2, 2005, the Board of Supervisors approved an amendment to the Suburban Propane, L.P. Severance Protection Plan for Key Employees (the “Severance Plan”) to provide that if any payment under the Severance Plan subjects a participant to the 20% federal excise tax under IRC Section 409A, the payment will be grossed up to permit such participant to retain a net amount on an after-tax basis equal to what he or she would have received had the excise tax not been payable. Mr. Alexander’s separation and consulting agreement does not meet the criteria under which IRC Section 4999 parachute excise tax is triggered. Additionally, it is the Partnership’s practice to comply with the statutory and regulatory provisions of IRC Section 409A; therefore, all payments associated with Mr. Alexander’s severance and consulting agreement will be made in accordance with the statutory and regulatory provisions of IRC Section 409A and, as a result, will not incur the 20% federal excise tax triggered by payments that violate said provisions. Employment Agreements Mr. Alexander, our Chief Executive Officer through the conclusion of fiscal 2009, and Mr. Dunn, our President (and Chief Executive Officer commencing with the start of fiscal 2010), are the only executive officers, named or otherwise, with whom we formerly had employment agreements. Mr. Alexander’s employment agreement remained in effect until the conclusion of fiscal 2009 in accordance with the terms of his separation and consulting agreement announced on April 23, 2009. At the conclusion of fiscal 2009, Mr. Alexander’s 76 employment agreement no longer had force or effect; instead, the provisions of his separation and consulting agreement went into effect. For more information regarding Mr. Alexander’s separation and consulting agreement, refer to the subsection below titled “Separation and Consulting Agreement of Mr. Alexander” and to the table below titled “Actual Payments to Mr. Alexander under His Separation and Consulting Agreement.” As a result of an agreement reached between Mr. Dunn and the Committee at its November 10, 2009 Committee meeting, Mr. Dunn’s employment agreement was terminated retroactively as of September 27, 2009 and replaced with a letter of agreement. For more information regarding Mr. Dunn’s letter of agreement, refer to the subsection below titled “Letter of Agreement of Mr. Dunn” and to the table below titled “Potential Payments upon Termination to Mr. Dunn under his Letter of Agreement.” In regard to the history of Mr. Alexander’s employment agreement, we entered into an employment agreement with him when it was announced, on March 5, 1996, that he would become our Chief Executive Officer. This agreement was subsequently amended on October 23, 1997, April 14, 1999 and November 2, 2005. In regard to the history of Mr. Dunn’s employment agreement, on February 5, 2007, we entered into an employment agreement with him that had an effective date of February 1, 2007. On November 13, 2008, the Committee approved an amendment to each of Mr. Alexander's and Mr. Dunn's employment agreements to bring these agreements into conformance with the final regulations issued by the IRS under IRC Section 409A. The final provisions of both Mr. Alexander’s and Mr. Dunn’s employment agreements were the results of negotiations between the Committee and each individual and are not reducible to a specific process. For example, Mr. Alexander was the only Chief Executive Officer that had been employed by the Partnership until Mr. Dunn assumed the role on September 27, 2009. As a result, some aspects of Mr. Alexander’s employment arrangements predate the existence of the Partnership and were agreed to by our former general partner. Over the years, when considering whether to renew Mr. Alexander’s contract, the Committee considered, among other factors, Mr. Alexander’s experience, performance and the fact that our headquarters are located in the New York Metropolitan area. Similar considerations applied to the circumstances under which Mr. Dunn’s employment agreement was negotiated. In particular, the Committee believed that the termination and change of control arrangements contained in both of these employment agreements were an important part of the competitive total compensation provided to our Chief Executive Officer and to our President. The Committee also believed that the termination and change of control provisions of Mr. Alexander’s and Mr. Dunn’s employment agreements were necessary to eliminate, or at least reduce, the possibility of reluctance on the part of our Chief Executive Officer and our President to pursue potential change of control transactions that might have been in the best interests of our Unitholders. These arrangements did not affect any decision made in fiscal 2009 with respect to any other compensation elements for our named executive officers. Employment Agreement of Mr. Alexander Mr. Alexander’s employment agreement had an initial term of three years, and was renewed automatically for all successive one-year periods through the end of fiscal 2009. The employment agreement provided for an annual base salary of $450,000 and provided Mr. Alexander with the opportunity to earn a cash bonus of up to 100% of base salary based upon the achievement of the same EBITDA-related performance criteria as contained in our annual cash bonus plan described in the section titled “Annual Cash Bonus Plan” above. Under our Partnership Agreement, the Committee had the authority to grant Mr. Alexander a bonus in excess of 100% if, in accordance with the terms of the annual cash bonus plan, our other executive officers earned bonuses exceeding their target bonuses for the fiscal year. The Committee exercised this authority in connection with Mr. Alexander’s cash bonus for fiscal 2007 in recognition of performance. For fiscal 2009, in accordance with the provisions of Mr. Alexander’s separation and consulting agreement, the Committee agreed to provide Mr. Alexander with a cash bonus payment of up to 110% of his base salary to parallel the cash bonuses earned by the other named executive officers under our annual cash bonus plan. Mr. Alexander’s employment agreement provided him the opportunity to participate in benefit plans made available to our other executive officers and our other key employees. Under the provisions of this agreement, 77 we also provided Mr. Alexander with a term life insurance policy with a face amount equal to three times his base salary. If, while Mr. Alexander’s employment agreement had force and effect, a change of control (as defined in the “Change of Control” section below) of the Partnership had occurred, and within six months prior thereto or at any time subsequent to such change of control, we had terminated Mr. Alexander’s employment without cause (as defined in the “Severance Benefits” section below) or if Mr. Alexander had resigned with good reason (as defined in the “Severance Benefits” section below) or had terminated his employment commencing on the six month anniversary and ending on the twelve month anniversary of such change of control, then Mr. Alexander would have been entitled to: • A lump sum severance payment equal to three times his annual base salary in effect as of the date of termination plus three times his annual cash bonus at 100%; and • Medical benefits for three years from the date of such termination. In situations unconnected to a change of control event, if the Partnership had terminated Mr. Alexander’s employment without cause or if Mr. Alexander had resigned with good reason, then Mr. Alexander would have been entitled to: • A severance payment equal to (A) the portion of his base salary earned but not paid as of the date of termination, (B) his pro-rata annual cash bonus under the employment agreement based upon the number of days worked during the fiscal year of termination, and (C) three times his annual base salary in effect as of the date of termination; and • Medical benefits for three years from the date of such termination reduced to the extent comparable benefits are provided to Mr. Alexander by another party. The employment agreement required that if any payment received by Mr. Alexander had been subject to the 20% excise tax under IRC Section 4999, the payment would have been increased to permit Mr. Alexander to retain a net amount on an after-tax basis equal to what he would have received had the excise tax not been payable. If Mr. Alexander’s employment had been terminated due to death, disability, or pursuant to delivery of a non- renewal notice to the Partnership in accordance with the terms and conditions of his employment agreement, he or his estate would have been entitled to earned but unpaid base salary plus his pro-rata cash bonus. If his employment had been terminated by the Partnership for cause, he would have been entitled to his earned but unpaid base salary only. Separation and Consulting Agreement of Mr. Alexander In order to provide for an orderly transition from his leadership as our Chief Executive Officer to that of his successor, after making his decision to resign as our Chief Executive Officer, Mr. Alexander entered into negotiations with the Board of Supervisors to plan an orderly transition. As a result of negotiations between Mr. Alexander and the Board of Supervisors, Mr. Alexander agreed to a termination of his existing employment agreement simultaneous with Mr. Dunn’s succession as our next Chief Executive Officer at the close of business on September 26, 2009. The following items are the essential elements of Mr. Alexander’s separation and consulting agreement that was entered into as a result of Mr. Alexander’s and the Board of Supervisor’s collaborative efforts to ensure an orderly transition: • Mr. Alexander was to remain our Chief Executive Officer until the close of business on September 26, 2009. At that time, Mr. Dunn would succeed him as our President and Chief Executive Officer. Mr. Alexander agreed not to stand for election to our Board of Supervisors at the July 22, 2009 Tri-Annual Meeting. 78 • Mr. Alexander’s existing employment agreement was to remain in effect until the end of fiscal 2009 and subsequently have no further force or effect. During the period between April 23, 2009 and September 26, 2009, the Board of Supervisors would retain the right to terminate the existing agreement for cause. During the period between April 23, 2009 and September 26, 2009, Mr. Alexander was permitted to seek other employment opportunities that were not inconsistent with the non-compete provisions of his separation and consulting agreement. • Mr. Alexander will remain bound to non-competition, non-solicitation and confidentiality obligations substantially identical to those contained in his former employment agreement, in each case, for the three year period commencing at the close of business on September 26, 2009. • For the three year period commencing at the close of business on September 26, 2009, Mr. Alexander will remain engaged by the Partnership as an independent consultant providing transitional assistance and strategic advice to the Board of Supervisors and to Mr. Dunn with respect to operational matters, acquisitions, dispositions and other transactional matters. • As payment for his three-year consulting services, Mr. Alexander will receive an aggregate consulting fee of $1,000,000, payable over the course of the three-year consulting period. • Mr. Alexander will be paid his fiscal 2009 cash bonus (110% of base salary), without proration. • Mr. Alexander received a payment ($444,030) under the SERP equal to what said payment would have been if Mr. Alexander had attained age 55 on September 26, 2009. • Mr. Alexander will be reimbursed for income tax preparation services for the filing of his 2009, 2010 and 2011 income tax returns. • We will continue to pay the lease expense and insurance on Mr. Alexander’s employer-provided vehicle for the three years during which he acts as a consultant. • We will pay for Mr. Alexander’s supplemental life insurance coverage for the three years during which • he acts as a consultant. In lieu of a fiscal 2009 matching contribution of $14,700 to Mr. Alexander’s 401(k), Mr. Alexander will receive a cash payment of $14,700 on or about the same day that fiscal 2009 matching contributions are made to the 401(k) accounts of the Partnership’s employees. • We will reimburse Mr. Alexander’s payments for medical and dental benefits coverage until he is covered under another employer’s medical/dental plan for a period not to exceed the three year consulting period. • Mr. Alexander has provided us with a general release from future litigation. He will retain his rights to indemnification and to director and officer insurance. • Mr. Alexander transferred his sole membership interest in the general partner to Mr. Dunn at the close of business on September 26, 2009. • The change of control benefits under Mr. Alexander’s existing employment agreement terminated at the close of business on September 26, 2009. However, if a change of control occurs during the three year period during which he provides consulting services to us, his consulting obligations will cease and he will be paid the remaining, unpaid portion of the agreed upon consulting fee of $1,000,000. In addition, he will receive payment of any unpaid LTIP-2 awards in accordance with the terms and conditions of the plan document. For comparative purposes, the section titled “Potential Payments Upon Termination” below includes a table containing hypothetical severance payments that would have been made under Mr. Alexander’s former employment agreement and another containing the actual payments he will receive under his separation and consulting agreement. Employment Agreement of Mr. Dunn Mr. Dunn’s employment agreement had an initial term of two years commencing on February 1, 2007, the term of which were to automatically renew for successive one-year periods, unless earlier terminated by us or by Mr. Dunn or otherwise terminated in accordance with the terms of the employment agreement. The provisions of 79 Mr. Dunn’s employment agreement provided for an initial annual base salary of $400,000 per year (which was permitted to be adjusted upwards annually at the Committee’s discretion) and, in accordance with the provisions of our annual cash bonus plan, the opportunity to earn a cash bonus in each fiscal year up to 110% of his annual base salary for each fiscal year (the “Maximum Annual Cash Bonus”). Additionally, Mr. Dunn’s employment agreement permitted his participation in the same benefit plans made available to our other executive officers and other key employees. If, while Mr. Dunn’s employment agreement had force and effect, a change of control (as defined in the “Change of Control” section below) of the Partnership had occurred and within six months prior thereto or within two years thereafter the Partnership had terminated Mr. Dunn’s employment without cause (as defined in the “Severance Benefits” section below) or if Mr. Dunn had resigned with good reason (as defined in the “Severance Benefits” section below), then Mr. Dunn would have been entitled to a severance payment equal to the sum of: • The portion of his base salary earned but not paid as of the date of termination; • His pro-rata cash bonus (the bonus Mr. Dunn would have been entitled to under the employment agreement for the full fiscal year in which the termination occurred multiplied by the number of days from the beginning of that fiscal year until the termination date and divided by 365); • Two times the sum of (1) his annual base salary in effect as of the date of termination, plus (2) the Maximum Annual Cash Bonus; and • Medical benefits for two years from the date of such termination. In situations unconnected to a change of control event, if the Partnership had terminated Mr. Dunn’s employment without cause, or if Mr. Dunn had resigned with good reason, then Mr. Dunn would have been entitled to: • A severance payment equal to (A) the portion of his base salary earned but not paid as of the date of termination, (B) the annual cash bonus Mr. Dunn would have been entitled to under the employment agreement for the full fiscal year in which the termination occurred had Mr. Dunn remained employed by the Partnership for that full fiscal year, and (C) two times his annual base salary in effect as of the date of termination; and • Medical benefits for two years from the date of such termination. The employment agreement required that if any payment received by Mr. Dunn had been subject to the 20% excise tax under IRC Section 4999, the payment would have been increased to permit Mr. Dunn to retain a net amount on an after-tax basis equal to what he would have received had the excise tax not been payable. If Mr. Dunn’s employment had been terminated due to death, disability, or pursuant to delivery of a non- renewal notice to the Partnership in accordance with the terms and conditions of his employment agreement, he or his estate, as the case may be, would have been entitled to earned but unpaid base salary plus his pro-rata cash bonus for the fiscal year during which termination occurred. If his employment were terminated by the Partnership for cause, or if he resigned without good reason, he would have been entitled to his earned but unpaid base salary only. Letter of Agreement of Mr. Dunn Simultaneous with the commencement of fiscal 2010, Mr. Dunn’s employment agreement was terminated and replaced with a letter of agreement governing retirement and the implementation of a mutually agreed upon succession plan. The letter of agreement between Mr. Dunn and us is summarized as follows: • Mr. Dunn will participate in our Severance Protection Plan at the 78-week participation level. 80 • 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: o A lump sum payment equal to two years of base salary. o Payment of medical benefits until attainment of age 65 (Mr. Dunn will be 63 at the conclusion of fiscal 2012). o Payment of unvested LTIP-2 awards held by Mr. Dunn at separation in accordance with the terms and conditions of the LTIP-2 plan document. o Transfer of ownership of employer-provided vehicle to Mr. Dunn. o Receipt of other vested and certain unvested benefits including restricted unit awards, earned cash bonus, pension plan in accordance with the terms and conditions of each plan. 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. For comparative purposes, the section titled “Potential Payments Upon Termination” below includes a table containing hypothetical severance payments that would have been made under the provisions Mr. Dunn’s former employment agreement and another containing hypothetical payments under the provisions of his letter of agreement. 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 2009, our Severance Protection Plan covered all executive officers, including the named executive officers, with the exception of our Chief Executive Officer and 81 our President, whose severance provisions were established in their respective employment agreements. The Severance Protection Plan provides for severance payments of either sixty-five or seventy-eight weeks of base salary and target cash bonuses for such officers and key employees following a change of control and termination of employment. All named executive officers who participate in the Severance Protection Plan are eligible for seventy-eight weeks of base salary and target bonuses. The cash components of any change of control benefits are paid in a lump sum. In addition, upon a change of control, without regard to whether a participant’s employment is terminated, all unvested awards granted under the RUP will vest immediately and become distributable to the participants and all outstanding, unvested LTIP-2 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). The SERP (as discussed above in the section titled “Supplemental Executive Retirement Plan”) will terminate effective on the close of business thirty days following the change of control. Mr. Dunn, the remaining participant, will be deemed to have retired and will have his respective benefits determined as of the date the plan is terminated with payment of his benefits no later than ninety days after the change of control. He will receive a lump sum payment equivalent to the present value of his benefit payable under the plan utilizing the lesser of the prime rate of interest as published in the Wall Street Journal as of the date of the change of control or one percent, as the discount rate to determine the present value of the accrued benefit. For purposes of the SERP, a change of control is deemed to occur, in general, if: • An acquisition of our Common Units or voting equity interests by any person immediately after which such person beneficially owns more than 25% of the combined voting power of our then outstanding Common Units, unless such acquisition was made by (a) us or our subsidiaries, Suburban Energy Services Group, LLC, or any employee benefit plan maintained by us, our Operating Partnership or any of our subsidiaries, or (b) any person in a transaction where (A) the existing holders prior to the transaction own at least 60% of the voting power of the entity surviving the transaction and (B) none of the Unitholders other than the Partnership, our subsidiaries, any employee benefit plan maintained by us, our Operating Partnership, or the surviving entity, or the existing beneficial owner of more than 25% of the outstanding Common Units owns more than 25% of the combined voting power of the surviving entity (such transaction, a “Non-Control Transaction”); or 82 • Approval by our partners of (a) a merger, consolidation or reorganization involving the Partnership other than a Non-Control Transaction; (b) a complete liquidation or dissolution of the Partnership; or (c) the sale or other disposition of 50% or more of our net assets to any person (other than a transfer to a subsidiary). For additional information pertaining to severance payable to our named executive officers following a change of control-related termination, see the tables titled “Potential Payments Upon Termination” below. Report of the Compensation Committee The Compensation Committee has reviewed and discussed with management this Compensation Discussion and Analysis. Based on its review and discussions with management, the Committee recommended to the Board of Supervisors that this Compensation Discussion and Analysis be included in this Annual Report on Form 10-K for fiscal 2009. The Compensation Committee: John Hoyt Stookey, Chairman John D. Collins Harold R. Logan, Jr. Dudley C. Mecum Jane Swift 83 ADDITIONAL INFORMATION REGARDING EXECUTIVE COMPENSATION Summary Compensation Table for Fiscal 2009 The following table sets forth certain information concerning the compensation of each named executive officer during the fiscal years ended September 26, 2009, September 27, 2008 and September 29, 2007: Name and Principal Position (a) Year (b) Salary ($)(1) (c ) Bonus ($)(2) (d) Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)(5) (h) Unit Awards ($)(3) (e) Non-Equity Incentive Plan Compensation ($)(4) (g) All Other Compensation ($)(6) (i) Total ($) (j) 2009 $450,000 - $367,525 $495,000 $ 64,042 $1,126,693 $2,503,260 2008 $450,000 - $171,606 $427,500 2007 $450,000 $ 45,000 $410,238 $456,188 Mark A. Alexander Chief Executive Officer Michael A. Stivala Chief Financial Officer & Chief Accounting Officer Michael J. Dunn, Jr. President Steven C. Boyd Vice President of Field Operations Michael M. Keating Senior Vice President of Administration Douglas T. Brinkworth Vice President of Product Supply 2009 $262,500 2008 $250,000 2007 $200,000 2009 $433,333 2008 $425,000 2007 $391,552 2009 $260,000 2008 $245,000 2007 $226,232 2009 $230,833 2008 $220,000 2007 $210,000 2009 $228,333 2008 $215,000 2007 $195,000 - - - - - - - - - - - - - - - - - - - - $ 46,926 $1,096,032 $ 52,507 $1,413,933 $ 41,728 $ 748,753 $ 32,589 $ 594,877 $ 32,356 $ 575,557 $230,025 $214,500 $157,913 $154,375 $210,370 $132,831 $719,286 $467,500 $ 56,050 $ 48,065 $1,724,234 $498,395 $403,750 - $ 38,976 $1,366,121 $824,713 $443,568 $ 6,752 $ 44,879 $1,711,464 $243,600 $214,500 $ 53,577 $ 39,811 $ 811,488 $178,116 $139,650 $243,910 $155,868 - - $ 26,406 $ 589,172 $ 34,202 $ 660,212 $218,072 $160,875 $ 107,821 $ 45,583 $ 763,184 $290,955 $135,850 - $ 35,109 $ 681,914 $266,908 $151,611 $ 5,648 $ 43,816 $ 677,983 $203,655 $185,625 $ 31,679 $ 43,440 $ 692,732 $148,463 $153,188 - $ 34,881 $ 551,532 $213,167 $129,758 - $ 41,720 $ 579,645 (1) Includes amounts deferred by named executive officers as contributions to the qualified 401(k) Plan. For more information on Mr. Alexander’s and Mr. Dunn’s base salaries, refer to the subheading titled “Employment Agreements” in the “Compensation Discussion and Analysis” above. During fiscal 2007, Mr. Stivala was not our Chief Financial Officer. His promotion from Controller to Chief Financial Officer was effective on September 30, 2007; therefore, the $50,000 increase between his fiscal 2007 and fiscal 2008 base salary is attributable to the increased responsibilities associated with his promotion. For more information on the relationship between salaries and other cash compensation (i.e., annual cash incentives and 2003 Long-Term Incentive Plan awards), refer to the subheading titled “Allocation Among Components” in the “Compensation Discussion and Analysis” above. 84 (2) For fiscal 2007, in recognition of performance, the Committee provided Mr. Alexander with an incentive payment equal to 110% of his target cash bonus to parallel the cash bonuses earned by the other named executive officers under the annual cash bonus plan. The amount reported in this column represents the additional 10% awarded to Mr. Alexander at the Committee's discretion. For fiscal 2009, as part of the negotiated terms of Mr. Alexander’s separation and consulting agreement, the Committee agreed to provide Mr. Alexander with a cash bonus payment of up to 110% of his base salary to parallel the cash bonuses earned by the other named executive officers under our annual cash bonus plan. Because the additional 10% for 2009 was pursuant to a written agreement (i.e., Mr. Alexander’s separation and consulting agreement), this amount has been reported in column ‘g’. (3) The amounts reported in this column represent the expense, before the application of forfeiture estimates, recognized in our fiscal 2009, 2008 and 2007 statements of operations with respect to RUP awards made in fiscal years 2009, 2008 and 2007, as well as in prior fiscal years, and for LTIP-2 awards made in fiscal years 2009, 2008 and 2007 as well as in prior fiscal years. The specific details regarding these plans are provided in the preceding “Compensation Discussion and Analysis” under the subheadings “2000 Restricted Unit Plan” and “2003 Long-Term Incentive Plan.” The breakdown for each plan with respect to each named executive officer is as follows: Plan Name 2009 RUP LTIP-2 Total 2008 RUP LTIP-2 Total 2007 RUP LTIP-2 Totals Mr. Alexander Mr. Stivala Mr. Dunn Mr. Boyd Mr. Keating Mr. Brinkworth $ N/A 367,528 $ 367,528 $ 105,677 124,348 $ 230,025 $ 337,490 381,796 $ 719,286 $ 111,438 132,162 $ 243,600 $ 87,177 130,895 $ 218,072 $ 80,802 122,853 $ 203,655 N/A $ 171,606 $ 171,606 N/A $ 410,238 $ 410,238 $ 81,983 75,930 $ 157,913 $ 309,366 189,029 $ 498,395 $ 94,480 83,636 $ 178,116 $ 160,358 130,597 $ 290,955 $ 65,106 83,357 $ 148,463 $ 82,507 127,863 $ 210,370 N/A $ 824,713 $ 824,713 $ 87,127 156,783 $ 243,910 $ 39,911 226,997 $ 266,908 $ 73,536 139,631 $ 213,167 Because Mr. Dunn has met the retirement eligibility criteria under the provisions of LTIP-2, all compensation expense relative to unvested awards granted to Mr. Dunn under this plan was recognized in full in the year the award is granted. Although Mr. Dunn has also met the retirement eligibility criteria under the RUP’s normative retirement provisions, at the discretion of the Committee, Mr. Dunn’s unvested fiscal 2008 RUP award must be held for three years from the grant date of December 3, 2007 before the retirement provisions become applicable. As a result, the expense associated with Mr. Dunn’s fiscal 2008 RUP award will be recognized over this three year period. Mr. Dunn’s December 3, 2007 RUP award of 29,533 units was granted in consideration of his responsibilities as the Partnership’s President and in consideration of his not having received a prior award under this plan. Because Mr. Keating satisfied the RUP and LTIP-2 retirement criteria during fiscal 2008, all remaining unrecognized expense relative to unvested awards held by him in fiscal 2008 was recognized during fiscal 2008. Additionally, all compensation expense relative to unvested awards granted to Mr. Keating during fiscal 2009 was fully recognized during fiscal 2009. (4) For fiscal 2009 and fiscal 2008, the amounts reported in this column represent each named executive officer's annual cash bonus earned in accordance with the performance measures discussed under the subheading “Annual Cash Bonus Plan” in the “Compensation Discussion and Analysis.” For fiscal 2007, the amounts included in this column also include the interest credits made on behalf of the remaining balances of LTIP-2’s predecessor plan. Because the remaining balances of the predecessor plan were distributed to the participants during November 2007, there were no fiscal 2009 or fiscal 2008 interest credits. The fiscal 2007 breakdown for each plan with respect to each named executive officer is as follows: Plan Name Cash Bonus LTIP-1 Interest Credits Totals Mr. Alexander $ 450,000 6,188 $ 456,188 Mr. Stivala $ 132,000 831 $ 132,831 Mr. Dunn $ 440,000 3,568 $ 443,568 Mr. Boyd $ 155,100 768 $ 155,868 Mr. Keating $ 150,150 1,461 $ 151,611 Mr. Brinkworth $ 128,700 1,058 $ 129,758 (5) The amounts reported in this column represent each named executive officer’s Cash Balance Plan earnings and for Messrs. Alexander and Dunn, SERP earnings for the year. The decline in values of pension and nonqualified deferred compensation balances for fiscal 2008 were ($150,315), ($23,157), ($29,043), ($57,881) and ($17,463) for Messrs. Alexander, Dunn, Boyd, Keating and Brinkworth, respectively. The decline in values of pension and nonqualified deferred compensation balances for fiscal 2007 were ($1,460), ($3,348) and ($1,339) for Messrs. Alexander, Boyd and Brinkworth, respectively. These amounts have been omitted from the table because they are negative. Mr. Stivala is not a participant in these plans. 85 (6) The amounts reported in this column consist of the following: Type of Compensation 401(k) Match Value of Annual Physical Examination Value of Partnership Provided Vehicle Tax Preparation Services Cash Balance Plan Administrative Fees Insurance Premiums Severance Payments Totals Type of Compensation 401(k) Match Value of Annual Physical Examination Value of Partnership Provided Vehicle Tax Preparation Services Cash Balance Plan Administrative Fees Insurance Premiums Totals Mr. Alexander $ - 1,300 11,819 3,500 1,500 19,082 1,126,693 $ 1,163,894 Mr. Alexander $ 3,450 1,500 11,395 5,000 1,500 24,081 $ 46,926 2009 Mr. Stivala $ 14,700 1,300 11,318 N/A N/A 14,410 N/A $ 41,728 2008 Mr. Stivala $ 3,450 1,500 12,647 N/A N/A 14,992 $ 32,589 2007 Mr. Dunn $ 14,700 N/A 12,205 3,000 1,500 16,660 N/A $ 48,065 Mr. Dunn $ 3,450 1,500 12,888 2,500 1,500 17,138 $ 38,976 Mr. Boyd $ 14,700 N/A 6,205 3,000 1,500 14,406 N/A $ 39,811 Mr. Boyd $ 3,450 N/A 6,549 900 1,500 14,007 $ 26,406 Mr. Alexander $ 13,500 1,200 Mr. Stivala $ 12,485 1,200 Mr. Dunn $ 13,500 1,200 Mr. Boyd $ 13,500 N/A Mr. Keating $ 14,200 1,300 11,015 3,000 1,500 14,568 N/A $ 45,583 Mr. Keating $ 3,300 1,200 11,522 2,500 1,500 15,087 $ 35,109 Mr. Brinkworth $ 13,825 N/A 10,610 3,000 1,500 14,505 N/A $ 43,440 Mr. Brinkworth $ 3,248 1,200 11,395 2,500 1,500 15,038 $ 34,881 Mr. Keating $ 12,697 1,500 Mr. Brinkworth $ 11,894 1,500 Type of Compensation 401(k) Match Value of Annual Physical Examination Value of Partnership Provided Vehicle or, in Mr. Stivala’s Case, Car Allowance Tax Preparation Services Cash Balance Plan Administrative Fees Insurance Premiums Totals 11,078 2,000 1,500 23,229 $ 52,507 4,675 N/A N/A 13,996 $ 32,356 10,198 2,000 1,500 16,481 $ 44,879 5,647 950 1,500 12,605 $ 34,202 11,522 2,000 1,500 14,597 $ 43,816 10,395 2,000 1,500 14,431 $ 41,720 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 2009 The following table sets forth certain information concerning grants of awards made to each named executive officer during the fiscal year ended September 26, 2009: Estimated Future Payments Under Non-Equity Incentive Plan Awards Estimated Future Payments Under Equity Incentive Plan Awards Target ($) (d) N/A $450,000 Maximum ($) (e) N/A $495,000 Target ($) (g) N/A Maximum ($) (h) N/A $191,936 $239,920 All Other stock Awards: Number of Shares of Stock or Units (#) Grant Date Fair Value of Stock and Option Awards ($) (5) (i) N/A (l) N/A 4,818 $87,177 $195,000 $214,500 N/A $425,000 N/A $467,500 $144,156 $180,195 N/A N/A N/A N/A $314,197 $392,746 $195,000 $214,500 $144,156 $180,195 $146,250 $160,875 $108,143 $135,179 $168,750 $185,625 $124,768 $155,960 2,570 $46,504 4,818 $87,177 3,212 $58,115 Phantom Units Underlying Equity Incentive Plan Awards (LTIP-2)(4) N/A 3,752 2,818 N/A 6,142 2,818 2,114 2,439 Name (a) Mark Alexander Michael Stivala Michael Dunn, Jr. Steven Boyd Michael Keating Douglas. Brinkworth Plan Name Grant Date Approval Date RUP (1) Bonus(2) LTIP-2(3) RUP(1) Bonus(2) LTIP-2(3) RUP (1) Bonus(2) LTIP-2(3) RUP (1) Bonus(2) LTIP-2(3) RUP (1) Bonus(2) LTIP-2(3) RUP (1) Bonus(2) LTIP-2(3) (b) N/A 28 Sep 08 28 Sep 08 1 Dec 08 28 Sep 08 28 Sep 08 1 Sep 09 28 Sep 08 28 Sep 08 1 Dec 08 28 Sep 08 28 Sep 08 1 Dec 08 28 Sep 08 28 Sep 08 1 Dec 08 28 Sep 08 28 Sep 08 N/A 13Nov 08 N/A 13Nov 08 13Nov 08 13Nov 08 (1) The quantities reported on these lines represent discretionary awards under the Partnership’s 2000 Restricted Unit Plan. RUP awards vest as follows: 25% of the award on the third anniversary of the grant date; 25% of the award on the fourth anniversary of the grant date; and 50% of the award on the fifth anniversary of the grant date. If a recipient has held an unvested award for at least six months; is 55 years or older; and has worked for the Partnership for at least ten years, an award held by such participant will vest six months following such participant’s 86 retirement if the participant retires prior to the conclusion of the normal vesting schedule unless the Committee exercises its discretionary authority to alter the applicability of the plan’s retirement provisions in regard to a particular award. On September 26, 2009, Mr. Dunn and Mr. Keating were the only named executive officers who held RUP awards and, at the same time, satisfied all three retirement eligibility criteria. However, as a condition of Mr. Dunn’s fiscal 2008 award, the Committee requires Mr. Dunn to hold his award for three years from the grant date before the plan’s retirement provisions become applicable. Detailed discussions of the general terms of the RUP and the facts and circumstances considered by the Committee in authorizing the 2009 awards to the named executive officers is included in the “Compensation Discussion and Analysis” under the subheading “2000 Restricted Unit Plan.” (2) Amounts reported on these lines are the targeted and maximum annual cash bonus compensation potential for each named executive officer under the annual cash bonus plan as described in the “Compensation Discussion and Analysis” under the subheading “Annual Cash Bonus Plan.” Actual amounts earned by the named executive officers for fiscal 2009 were equal to 110% of the “Target” amounts reported on this line. Column (c) (“Threshold $”) was omitted because the annual cash bonus plan does not provide for a minimum cash payment. Because these plan awards were granted to, and 110% of the “Target” awards were earned by, our named executive officers during fiscal 2009, 110% of the “Target” amounts reported under column (d) have been reported in the Summary Compensation Table above. (3) LTIP-2 is a phantom unit plan. As discussed in the “Compensation Discussion and Analysis” above, under the subheading “2003 Long-Term Incentive Plan,” in accordance with a verbal agreement between Mr. Alexander and the Board of Supervisors, Mr. Alexander’s award is based upon 30% of his annual target cash bonus; however, Mr. Dunn’s award (as are the awards of all of the other named executive officers) is based upon 52% of his annual target cash bonus. The different percentages account for the apparent differences between amounts reported for Mr. Alexander and for Mr. Dunn. Payments, if earned, are based on a combination of (1) the fair market value of our Common Units at the end of a three-year measurement period, which, for purposes of the plan, is the average of the closing prices for the twenty business days preceding the conclusion of the three- year measurement period, and (2) cash equal to the distributions that would have inured to the same quantity of outstanding Common Units during the same three-year measurement period. The fiscal 2009 award “Target ($)” 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 26, 2009) of our Common Units at the end of fiscal 2009, and (2) the estimated distributions over the course of the award’s three-year measurement period. Column (f) (“Threshold $”) was omitted because LTIP-2 does not provide for a minimum cash payment. Detailed descriptions of the plan and the calculation of awards are included in the “Compensation Discussion and Analysis” under the subheading “2003 Long-Term Incentive Plan.” (4) This column is frequently used when non-equity incentive plan awards are denominated in units; however, in this case, the numbers reported represent the phantom units each named executive officer was awarded under LTIP-2 during fiscal 2009. (5) The dollar amounts reported in this column represent the aggregate fair value of the RUP awards on the grant date, net of estimated future distributions during the vesting period. The fair value shown may not be indicative of the value realized in the future upon vesting due to the variability in the trading price of our Common Units. Note: Columns (j) and (k) were omitted from the Grants of Plan Based Awards Table because the Partnership does not award options to its employees. Outstanding Equity Awards at Fiscal Year End 2009 Table The following table sets forth certain information concerning outstanding equity awards under our 2000 Restricted Unit Plan and phantom equity awards under our 2003 Long-Term Incentive Plan for each named executive officer as of September 26, 2009 (no awards were granted under our 2009 Restricted Unit Plan as of such date): Name (a) Mark A. Alexander Michael A. Stivala(1) Michael J. Dunn, Jr. (2) Steven C. Boyd(3) Michael M. Keating(4) Douglas T. Brinkworth(5) Stock Awards Number of Shares or Units of Stock That Have Not Vested (#)(6) Market Value of Shares or Units of Stock That Have Not Vested ($)(7) Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights that Have Not Vested (#)(8) (g) - 16,694 29,533 16,874 10,424 14,252 (h) - $ 689,212 $1,219,270 $ 696,643 $ 430,355 $ 588,394 (i) 6,741 4,689 11,036 4,511 3,761 4,296 Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($)(9) (j) $344,206 $239,471 $563,515 $230,404 $192,047 $219,370 87 (1) Mr. Stivala’s RUP awards will vest as follows: Vesting Date Quantity of Units Oct. 1, 2009 Nov 1, 2009 Apr 25, 2010 Oct 1, 2010 Nov 1, 2010 Dec 3, 2010 Apr 25, 2011 Dec 1, 2011 Dec 3, 2011 Apr 25, 2012 Dec 1, 2012 Dec 3, 2012 Dec 1, 2013 870 900 1,374 1,738 600 568 1,374 1,205 568 2,748 1,205 1,136 2,408 (2) Despite Mr. Dunn’s having met the plan’s retirement criteria (explained under the subheading “2000 Restricted Unit Plan” in the “Compensation Discussion and Analysis”), Mr. Dunn’s fiscal 2008 RUP award of 29,533 unvested units will not be subject to the plan’s retirement provisions until December 3, 2010. For more information on this and the retirement provisions, refer to the subheading “2000 Restricted Unit Plan” in the “Compensation Discussion and Analysis.” If Mr. Dunn does not retire prior to the conclusion of the normal vesting schedule of his RUP awards, his RUP awards will vest as follows: Vesting Date Quantity of Units Dec 3, 2010 Dec 3, 2011 Dec 3, 2012 7,384 7,384 14,765 (3) Mr. Boyd’s RUP awards will vest as follows: Vesting Date Quantity of Units Nov 1, 2009 Apr 25, 2010 Nov 1, 2010 Dec 3, 2010 Apr 25, 2011 Dec 1, 2011 Dec 3, 2011 Apr 25, 2012 Dec 1, 2012 Dec 3, 2012 Dec 1, 2013 2,200 1,374 3,200 852 1,374 643 852 2,748 643 1,704 1,284 (4) Mr. Keating met the retirement eligibility criteria (explained under the subheading “2000 Restricted Unit Plan” in the “Compensation Discussion and Analysis”) during fiscal 2008. If he does not retire prior to the conclusion of the normal vesting schedule of his RUP awards, his RUP awards will vest as follows: Vesting Date Quantity of Units Apr 25, 2010 Dec 3, 2010 Apr 25, 2011 Dec 1, 2011 Dec 3, 2011 Apr 25, 2012 Dec 1, 2012 Dec 3, 2012 Dec 1, 2013 550 852 550 1,205 852 1,098 1,205 1,704 2,408 (5) Mr. Brinkworth’s RUP awards will vest as follows: Vesting Date Quantity of Units Oct 1, 2009 Nov 1, 2009 Apr 25, 2010 Oct 1, 2010 Nov 1, 2010 Dec 3, 2010 Apr 25, 2011 Dec 1, 2011 Dec 3, 2011 Apr 25 2012 Dec 1, 2012 Dec 3, 2012 Dec 1, 2013 870 1,525 413 1,738 1,850 852 413 803 852 823 803 1,704 1,606 (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 25, 2009, the last trading day of fiscal 2009. (8) The amounts reported in this column represent the quantities of phantom units that underlie the outstanding and unvested fiscal 2008 and fiscal 2009 awards under LTIP-2. Payments, if earned, will be made to participants at the end of a three-year measurement period and will be based upon our total return to Common Unitholders in comparison to the total return provided by a predetermined peer group of eleven other companies, all of which are publicly-traded partnerships, to their unitholders. For more information on LTIP-2, refer to the subheading “2003 Long-Term Incentive Plan” in the “Compensation Discussion and Analysis.” (9) The amounts reported in this column represent the estimated future target payouts of the fiscal 2008 and fiscal 2009 LTIP-2 awards. These amounts were computed by multiplying the quantities of the unvested phantom units in column (i) by the average of the closing prices of our Common Units for the twenty business days preceding September 26, 2009 (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: Fiscal 2008 Phantom Units Value of Fiscal 2008 Phantom Units Estimated Distributions over Measurement Period Fiscal 2009 Phantom Units Value of Fiscal 2009 Phantom Units Estimated Distributions over Measurement Period Mr. Alexander 2,989 Mr. Stivala 1,871 Mr. Dunn 4,894 Mr. Boyd 1,693 Mr. Keating 1,647 Mr. Brinkworth 1,857 $ 123,447 $ 77,273 $ 202,125 $ 69,922 $ 68,022 $ 76,695 $ 28,823 $ 18,042 $ 47,193 $ 16,326 $ 15,882 $ 17,907 3,752 2,818 6,142 2,818 2,114 2,439 $ 154,960 $ 116,385 $ 253,667 $ 116,385 $ 87,309 $ 100,732 $ 36,976 $ 27,771 $ 60,530 $ 27,771 $ 20,834 $ 24,036 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. 88 Equity Vested Table for Fiscal 2009 Awards under the 2000 Restricted Unit Plan are settled in Common Units upon vesting. Awards under the 2003 Long-Term Incentive Plan, a phantom-equity plan, are settled in cash. The following two tables set forth certain information concerning the vesting of awards under our 2000 Restricted Unit Plan and the vesting of the fiscal 2007 award under our 2003 Long-Term Incentive Plan for each named executive officer during the fiscal year ended September 26, 2009: 2000 Restricted Unit Plan Unit Awards Name Mark A. Alexander Michael A. Stivala Michael J. Dunn, Jr. Steven C. Boyd Michael M. Keating Douglas T. Brinkworth Number of Common Units Acquired on Vesting (#) - 2,070 - 2,500 - 2,695 Value Realized on Vesting ($)(1) - $69,528 - $84,150 - $90,566 (1) The value realized is equal to the average of the high and low trading prices of our Common Units on the vesting date, multiplied by the number of units that vested. 2003 Long-Term Incentive Plan – Fiscal 2007(2) Award Cash Awards Name Mark A. Alexander Michael A. Stivala Michael J. Dunn, Jr. Steven C. Boyd Michael M. Keating Douglas T. Brinkworth Number of Phantom Units Acquired on Vesting (#)(3) 4,007 1,603 6,174 2,037 2,107 1,806 Value Realized on Vesting ($)(4) $254,479 $101,004 $389,020 $128,305 $132,761 $113,795 (2) The fiscal 2007 award’s three-year measurement period concluded on September 26, 2009. (3) In accordance with the formula described in the “Compensation Discussion and Analysis” under the subheading “2003 Long-Term Incentive Plan,” these quantities were calculated at the beginning of the three-year measurement period and were, therefore, based upon each individual’s salary and target cash bonus at that time. (4) The value (i.e., cash payment) realized was calculated in accordance with the terms and conditions of LTIP-2. For more information, refer to the subheading “2003 Long-Term Incentive Plan” in the “Compensation Discussion and Analysis.” 89 Pension Benefits Table for Fiscal 2009 The following table sets forth certain information concerning each plan that provides for payments or other benefits at, following, or in connection with retirement for each named executive officer as of the end of the fiscal year ended September 26, 2009: Name Mark A. Alexander Plan Name SERP (1) Cash Balance Plan (2) Number of Years Credited Service (#) 7 7 Present Value of Accumulated Benefit ($) $ 444,030 $ 216,432 Payments During Last Fiscal Year ($) $ 444,030 $ - Michael A. Stivala(3) N/A N/A $ - $ - Michael J. Dunn, Jr. SERP (1) Cash Balance Plan (2) LTIP-2 (4) RUP(5) Steven C. Boyd Cash Balance Plan (2) Michael M. Keating Cash Balance Plan (2) LTIP-2 (4) RUP(5) 6 6 N/A N/A 15 15 N/A N/A $ 51,610 $ 220,698 $ 563,515 N/A $ - $ - $ - $ - $ 120,322 $ - $ 388,163 $ 192,047 $ 430,355 $ - $ - $ - Douglas T. Brinkworth Cash Balance Plan (2 6 $ 75,716 $ - (1) Mr. Dunn is the sole remaining SERP participant. In accordance with the terms of Mr. Alexander’s separation and consulting agreement, the figure reported on this line is the payment he received and represents the accumulated benefit due to Mr. Alexander if he had remained in our employ until attaining age 55. For more information on the SERP, refer to the subheading “Supplemental Executive Retirement Plan” in the “Compensation Discussion and Analysis.” (2) For more information on the Cash Balance Plan, refer to the subheading “Pension Plan” in the “Compensation Discussion and Analysis.” (3) Because Mr. Stivala commenced employment with the Partnership after January 1, 2000, the date on which the Cash Balance Plan was closed to new participants, he does not participate in the Cash Balance Plan. (4) Currently, Mr. Dunn and Mr. Keating are the only named executive officers who meet the retirement criteria of the LTIP-2 plan document. For such participants, upon retirement, outstanding but unvested LTIP-2 awards become fully vested. However, payouts on those awards are deferred until the conclusion of each outstanding award’s three-year measurement period, based on the outcome of the TRU relative to the peer group. The number reported on this line represents a projected payout of Mr. Dunn’s and Mr. Keating’s outstanding fiscal 2008 and fiscal 2009 LTIP-2 awards. Because the ultimate payout, if any, is predicated on the trading prices of the Partnership’s Common Units at the end of the three-year measurement period, as well as where within the peer group our TRU falls, the value reported may not be indicative of the value realized in the future upon vesting due to the variability in the trading price of our Common Units. (5) Currently, Mr. Dunn and Mr. Keating are the only named executive officers who meet the retirement criteria of the RUP document. Despite Mr. Dunn’s having met the plan’s retirement criteria, his fiscal 2008 award will not be subject to the plan’s retirement provisions until December 3, 2010. For more information on this and the retirement provisions, refer to the subheading “2000 Restricted Unit Plan” 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. The value reported in this table on behalf of Mr. Keating represents the value of 10,424 Common Units using the average of the highest and the lowest trading prices of our Common Units on September 25, 2009. Potential Payments Upon Termination Potential Payments upon Termination to Named Executive Officers with Employment Agreements Although concurrent with the beginning of fiscal 2010, Mr. Alexander’s employment agreement no longer has force or effect and Mr. Dunn agreed to the termination of his employment agreement in exchange for a letter of agreement and participation in the Severance Protection Plan, the following table sets forth certain information concerning the potential payments to Mr. Alexander and Mr. Dunn under their former employment agreements, the SERP, LTIP-2 and the RUP for the hypothetical circumstances listed in the table assuming a September 26, 2009 termination date. Ancillary tables follow this table to illustrate the payments that Mr. Alexander will 90 actually receive under his separation and consulting agreement and to illustrate potential payments to Mr. Dunn in accordance with the letter of agreement between him and the Board of Supervisors that went into effect and replaced his employment agreement as of the beginning of fiscal 2010. Executive Payments and Benefits Upon Termination Death Disability Mark A. Alexander Cash Compensation(1) Accelerated Vesting of Fiscal 2008 and 2009 LTIP-2 Awards(2) SERP(5) Medical Benefits 280G Tax Gross-up 409A Tax Gross-up Total Michael J. Dunn, Jr. Cash Compensation(1) Accelerated Vesting of Fiscal 2008 and 2009 LTIP-2 Awards(2) Accelerated Vesting of Outstanding RUP Awards(6) SERP Medical Benefits 280G Tax Gross-up 409A Tax Gross-up $ -0-(3) N/A 227,800 N/A N/A N/A $ 227,800 $ -0-(3) N/A N/A 30,300 N/A N/A N/A Total $ 30,300 $ -0-(4) N/A 477,000 N/A N/A N/A $ 477,000 $ -0-(4) N/A 1,219,270 53,500 N/A N/A N/A $ 1,272,770 Involuntary Termination Without Cause by the Partnership or by the Executive for Good Reason without a Change of Control Event Involuntary Termination Without Cause by the Partnership or by the Executive for Good Reason with a Change of Control Event $ 1,350,000 N/A N/A 26,307 N/A N/A $ 1,376,307 $ 950,000 N/A N/A 53,500 23,384 N/A N/A $ 1,026,884 $ 2,835,000 386,974 662,700 26,307 N/A N/A $ 3,910,981 $ 1,995,000 633,534 1,219,270 51,800 23, 384 N/A N/A $ 3,922,988 (1) For additional information on the cash compensation that would have been payable to Mr. Alexander and Mr. Dunn under the provisions of their respective former employment agreements if any of the four hypothetical events had occurred at the conclusion of fiscal 2009, refer to the subheading “Employment Agreements” in the “Compensation Discussion and Analysis.” (2) In the event of a change of control, all LTIP-2 awards will vest immediately regardless of whether termination immediately follows. If a change of control event occurs, the calculation of the LTIP-2 payment will be made as if our total return to our Common Unitholders in the top quartile of the peer group. 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 and risks 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. (3) Under their former employment agreements, in the event of death, Mr. Alexander’s and Mr. Dunn’s estates would have been entitled to a payment equal to the decedent’s earned but unpaid salary and pro-rata cash bonus at the time of death. (4) Under their former employment agreements, in the event of disability, each is entitled to a payment equal to his earned but unpaid salary and pro-rata cash bonus. (5) Because Mr. Alexander had not attained age 55 on September 26, 2009, had it not been for the terms of his separation and consulting agreement, if any of the above hypothetical events had occurred on that date, without regard to the terms of his separation and consulting agreement that superseded the normative provisions of the SERP, only death, disability or a change of control would have given rise to a SERP-related payment. Change of control related payments are due to Mr. Alexander and Mr. Dunn within 30 days of the change of control event, regardless of whether termination or resignation follows the event. In the event of death, Mr. Alexander’s estate would have received a lump sum payment of $227,800. In the event of disability, if Mr. Alexander remained disabled until age 55, he would be eligible for a lump sum payment, at that time, of $960,300. The figure $477,000 reported in the table represents the present value of the hypothetical future payment. (6) The RUP document makes no provisions for the vesting of 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’s fiscal 2008 RUP award of 29,533 units was granted more than one year prior to September 26, 2009, if he had become permanently disabled on September 26, 2009, his fiscal 2008 RUP award would have vested. 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. 91 Actual Payments to Mr. Alexander under His Separation and Consulting Agreement The following table provides information concerning the Partnership’s separation and consulting agreement with Mr. Alexander who was succeeded as our Chief Executive Officer by Mr. Dunn on September 27, 2009: Executive Payments and Benefits Upon Termination Cash Compensation(1) Annual Cash Bonus(2) Payment of Remaining LTIP-2 Awards(3) Vehicle(4) Medical Benefits & Supplemental Life Insurance Coverage(5) Income Tax Preparation Services for Three Years(6) SERP Payment(7) 280(G)Tax Gross-up 409(A)Tax Gross-up Total Payments Received for Orderly Plan of Succession: Separation and Consulting Agreement $ 1,000,000 495,000 344,206 58,947 57,246 10,500 444,030 N/A N/A $ 2,409,929 (1) The amount reported on this line represents the aggregate consulting fee that Mr. Alexander will receive for the three-year consulting period commencing on September 27, 2009. During the consulting period, Mr. Alexander will provide transitional assistance and strategic advice to the Board of Supervisors and to Mr. Dunn. This amount will be paid in bi-weekly installments over the course of the three-year consulting period and has been reported in the column titled “All Other Compensation ($)” in the Summary Compensation Table above. (2) The amount reported on this line represents Mr. Alexander’s full annual cash bonus, without pro-ration, for fiscal 2009 and has been reported in the column titled “Non-Equity Incentive Plan Compensation ($)” in the Summary Compensation Table above. (3) The amount reported on this line represents the estimated payments of Mr. Alexander’s two remaining, unvested LTIP-2 awards (i.e., the fiscal 2008 and 2009 awards). Mr. Alexander’s fiscal 2008 and 2009 awards will be paid, if earned, in accordance with the provisions of the LTIP-2 plan document. Because Mr. Alexander, the service provider, has no additional services to perform in order to receive any cash payments for these awards, all remaining, unamortized compensation expense associated with these awards was recognized during fiscal 2009 and has been reported in the column titled “Unit Awards ($)” in the Summary Compensation Table above. (4) The amount reported on this line represents the imputed fair market value for use of a vehicle provided by the Partnership and the estimated cost of fuel for the vehicle during the three-year consulting period and has been reported in the column titled “All Other Compensation ($)” in the Summary Compensation Table above. (5) The amount reported on this line represents the estimated cost of health insurance premiums and supplemental life insurance coverage during the three-year consulting period and has been reported in the column titled “All Other Compensation ($)” in the Summary Compensation Table above. (6) The amount reported on this line represents the estimated cost to reimburse Mr. Alexander for income tax preparation services for three years and has been reported in the column titled “All Other Compensation ($)” in the Summary Compensation Table above. (7) The amount reported on this line represents the lump-sum payment under the SERP equal to what said payment would have been if Mr. Alexander had attained age 55 on September 26, 2009. In accordance with the provisions of Mr. Alexander’s separation and consulting agreement, this amount was paid within thirty days of the conclusion of fiscal 2009. All above market interest credits relative to this payment have been reported in the column titled “Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)” in the Summary Compensation Table above. 92 Potential Payments upon Termination to Mr. Dunn under his Letter of Agreement The following table sets forth certain information containing potential payments to Mr. Dunn under the letter of agreement between him and the Partnership and in accordance with the provisions of the Severance Protection Plan, the RUP and LTIP-2 for the circumstances listed in the table assuming a September 26, 2009 termination date: Involuntary Termination Without Cause by the Partnership or by the Executive for Good Reason without a Change of Control Event Involuntary Termination Without Cause by the Partnership or by the Executive for Good Reason with a Change of Control Event Terminati on as a Result of Retirement or an Agreed- Upon Succession Plan in Accordanc e with the Letter of Agreement between Mr. Dunn and the Board Executive Payments and Benefits Upon Termination Death Disability Michael J. Dunn Cash Compensation Accelerated Vesting of Fiscal 2008 and 2009 LTIP-2 Awards(6) Accelerated Vesting of Outstanding RUP Awards(7) SERP(8) Medical Benefits(3) 280G Tax Gross-up 409A Tax Gross-up Total $ -0-(1) $ -0-(2) $ 475,000(3) $ 1,425,000(4) $ -0-(5) N/A N/A 30,300 N/A N/A N/A $ 30,300 N/A 1,219,270 53,500 N/A N/A N/A $ 1,272,770 N/A N/A 53,500 N/A 11,692 N/A $ 540,192 633,534 1,219,270 51,800 N/A N/A N/A $ 3,329,604 N/A N/A N/A N/A N/A N/A $ N/A (1) In the event of death, Mr. Dunn’s estate would be entitled to a payment equal to his earned but unpaid salary and pro-rata cash bonus. (2) In the event of disability, Mr. Dunn would be 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 Mr. Dunn 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 Mr. Dunn would, upon termination of employment without cause or for resignation for good reason, receive accrued salary and benefits through the date of termination plus one times annual salary, paid in the form of salary continuation, and continued participation, at active employee rates, in the Partnership’s health insurance plans for one year. (4) (5) (6) In the event of a change of control followed by a termination without cause or by a resignation with good reason, Mr. Dunn, and each of the other named executive officers without employment agreements or letters of understanding, 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.” In accordance with the terms of Mr. Dunn’s letter of agreement, if he retires prior to the last day of fiscal 2012, the assumptions contained in footnote 3 (above) will govern. If, in accordance with an agreed upon succession plan, he were to retire on the last day of fiscal 2012 or anytime thereafter, he will receive a lump-sum cash payment equal to two years of his base salary at that time. In the event of a change of control, all LTIP-2 awards will vest immediately regardless of whether termination immediately follows. If a change of control event occurs, the calculation of the LTIP-2 payment will be made as if our total return to Common Unitholders was in the top quartile of the peer group. 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. (7) 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’s fiscal 2008 RUP award of 29,533 units was granted more than one year 93 prior to September 26, 2009, if he had become permanently disabled on September 26, 2009, his fiscal 2008 RUP award would have vested; however, because his fiscal 2009 RUP award of 25,000 units was granted less than one year prior to September 26, 2009, his fiscal 2009 RUP award would have been forfeited. 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. (8) Because Mr. Dunn attained age 55 prior to September 26, 2009, if any of the above hypothetical events had occurred on that date, each event would give rise to a SERP-related payment. Potential Payments upon Termination to Named Executive Officers without Employment Agreements The following table sets forth certain information containing potential payments to the three named executive officers without employment agreements in accordance with the provisions of the Severance Protection Plan, the RUP and LTIP-2 for the circumstances listed in the table assuming a September 26, 2009 termination date: Executive Payments and Benefits Upon Termination Death Disability Involuntary Termination Without Cause by the Partnership or by the Executive for Good Reason without a Change of Control Event Involuntary Termination Without Cause by the Partnership or by the Executive for Good Reason with a Change of Control Event Michael A. Stivala Cash Compensation(1) (2) (3) (4) Accelerated Vesting of Fiscal 2008 and 2009 LTIP-2 Awards(5) Accelerated Vesting of Outstanding RUP Awards(6) Medical Benefits(3) 280G Tax Gross-up 409A Tax Gross-up Total Steven C. Boyd Cash Compensation(1) (2) (3) (4) Accelerated Vesting of Fiscal 2008 and 2009 LTIP-2 Awards(5) Accelerated Vesting of Outstanding RUP Awards(6) Medical Benefits(3) 280G Tax Gross-up 409A Tax Gross-up Total Michael M. Keating Cash Compensation(1) (2) (3) (4) Accelerated Vesting of Fiscal 2008 and 2009 LTIP-2 Awards(5) Accelerated Vesting of Outstanding RUP Awards(6) Medical Benefits(3) 280G Tax Gross-up 409A Tax Gross-up Total Douglas T. Brinkworth Cash Compensation(1) (2) (3) (4) Accelerated Vesting of Fiscal 2008 and 2009 LTIP-2 Awards(5) Accelerated Vesting of Outstanding RUP Awards(6) Medical Benefits(3) 280G Tax Gross-up 409A Tax Gross-up Total $ -0- N/A 490,301 N/A N/A N/A $ 490,301 $ -0- N/A 590,541 N/A N/A N/A $ 590,541 $ 275,000 N/A N/A 11,692 N/A N/A $ 286,692 $ 260,000 N/A N/A 11,422 N/A N/A $ 271,422 $ 721,875 268,374 689,212 N/A N/A N/A $ 1,679,461 $ 682,500 257,774 696,643 N/A N/A N/A $ 1,636,917 $ -0- N/A 231,444 N/A N/A N/A $ 231,444 $ 260,000 N/A N/A 11,692 N/A N/A $ 271,692 $ 663,000 215,824 430,355 N/A N/A N/A $ 1,309,179 $ -0- N/A 455,786 N/A N/A N/A $ 455.786 $ 245,000 N/A N/A 11,692 N/A N/A $ 256,692 $ 643,125 246,432 588,394 N/A N/A N/A $ 1,477,951 $ -0- N/A N/A N/A N/A N/A $ 0 $ -0- N/A N/A N/A N/A N/A $ 0 $ -0_ N/A N/A N/A N/A N/A $ 0 $ -0_ N/A N/A N/A N/A N/A $ 0 94 (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, paid in the form of salary continuation, and continued participation, at active employee rates, in the Partnership’s health insurance plans for one year. (4) (5) In the event of a change of control followed by a termination without cause or by a resignation with good reason, each of the named executive officers without employment agreements will receive 78 weeks of base pay plus a sum equal to their annual target cash bonus divided by 52 and multiplied by 78 in accordance with the terms of the Severance Protection Plan. For more information on the Severance Protection Plan, refer to the subheading “Change of Control” in the “Compensation Discussion and Analysis.” In the event of a change of control, all LTIP-2 awards will vest immediately regardless of whether termination immediately follows. If a change of control event occurs, the calculation of the LTIP-2 payment will be made as if our total return to Common Unitholders was higher than that provided by any of the other members of the peer group to their unitholders. For more information, refer to the subheading “2003 Long-Term Incentive Plan” in the “Compensation Discussion and Analysis.” In the event of death, the inability to continue employment due to permanent disability, or a termination without cause or a good reason resignation unconnected to a change of control event, awards will vest in accordance with the normal vesting schedule and will be subject to the same requirements as awards held by individuals still employed by the Partnership and 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. Stivala, Mr. Boyd, Mr. Keating and Mr. Brinkworth each received a RUP award during fiscal 2009, if any or all of the three had become permanently disabled on September 26, 2009, the following quantities of unvested restricted units would have vested: Stivala, 11,876; Boyd, 14,304; Keating, 5,606; Brinkworth, 11,040 and the following quantities would have been forfeited: Stivala, 4,818; Boyd, 2,570; Keating, 4,818; Brinkworth, 3,212. 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. 95 SUPERVISORS’ COMPENSATION The following table sets forth the compensation of the non-employee members of the Board of Supervisors of the Partnership during fiscal 2009. Supervisor John D. Collins Harold R. Logan, Jr. Dudley C. Mecum John Hoyt Stookey Jane Swift Fees Earned or Paid in Cash ($) (1) Unit Awards ($) (2) Total ($) $ 75,000 100,000 75,000 75,000 75,000 $ 49,861 - - - 49,861 $ 124,861 100,000 75,000 75,000 124,861 (1) Includes amounts earned for fiscal 2009, including quarterly retainer installments for the fourth quarter of 2009 that were paid in October 2009. Does not include amounts paid in fiscal 2009 for fiscal 2008 quarterly retainer installments. (2) Represents the dollar amount charged to earnings for financial statement reporting purposes during fiscal 2009 for restricted unit awards of 5,496 awarded to both Mr. Collins and Ms. Swift on April 25, 2007. All awards were made in accordance with the provisions of our 2000 Restricted Unit Plan and vest accordingly. The average of the high and low sales price, discounted for projected distributions during the vesting period, was used to calculate the value of the restricted unit awards for purposes of amortizing compensation expense. Because Messrs. Logan, Mecum and Stookey have satisfied the plan’s retirement provisions, all expense for their unvested awards was previously recognized. As of September 26, 2009, each non-employee member of the Board of Supervisors held the following quantities of unvested restricted unit awards: Mr. Collins, 5,496 units; Mr. Logan, 7,250 units; Mr. Mecum, 7,250 units; Mr. Stookey, 7,250 units; and Ms. Swift, 5,496 units. Note: The columns for reporting option awards, non-equity incentive plan compensation, changes in pension value and non-qualified deferred compensation plan earnings and all other forms of compensation were omitted from the Supervisor’s Compensation Table because the Partnership does not provide these forms of compensation to its non-employee supervisors. Fees and Benefit Plans for Non-Employee Supervisors Annual Cash Retainer Fees. As the Chairman of the Board of Supervisors, Mr. Logan receives an annual retainer of $100,000, payable in quarterly installments of $25,000 each. Each of the other 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 Plan. Each non-employee Supervisor participates in the 2000 and 2009 Restricted Unit Plans. All awards vest in accordance with the provisions of the plan document (see “Compensation Discussion and Analysis” sections titled “2000 Restricted Unit Plan” and “2009 Restricted Unit Plan” 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. 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 2009 for each Supervisor. Compensation Committee Interlocks and Insider Participation. None. 96 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, 2009 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. Name of Beneficial Owner Mark A. Alexander Michael J. Dunn, Jr. (a) Michael A. Stivala (b) Steven C. Boyd (c) Michael M. Keating (d) Douglas T. Brinkworth (e) John Hoyt Stookey (f) Harold R. Logan, Jr.(f) Dudley C. Mecum (f) John D. Collins (g) Jane Swift (g) All Members of the Board of Supervisors and Executive Officers (including former CEO, Mark Alexander) as a Group (17 persons) (h) Amount and Nature of Beneficial Ownership (1) 1,298,912 208,947 10,732 31,933 98,500 25,395 18,322 17,044 14,134 12,450 -0- Percent of Class 3.7% * * * * * * * * * * 1,831,336 5.2% (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 29,533 unvested restricted units, none of which will vest in the 60-day period following November 23, 2009. (b) Excludes 14,924 unvested restricted units, none of which will vest in the 60-day period following November 23, 2009. (c) Excludes 14,674 unvested restricted units, none of which will vest in the 60-day period following November 23, 2009. (d) Excludes 10,424 unvested restricted units, none of which will vest in the 60-day period following November 23, 2009. (e) Excludes 11,857 unvested restricted units, none of which will vest in the 60-day period following November 23, 2009. 97 (f) Excludes 3,000 unvested restricted units, none of which will vest in the 60-day period following November 23, 2009. (g) Excludes 5,496 unvested restricted units, none of which will vest in the 60-day period following November 23, 2009. (h) Inclusive of the units referred to in footnotes (a), (b), (c), (d), (e), (f) and (g) above, the reported number of units excludes 157,110 unvested restricted units, none of which will vest in the 60 day period following November 23, 2009, 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 26, 2009, 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 Common Units to be issued upon vesting of restricted units (a) 415,295 (2) -- 415,295 Weighted-average grant date fair value per restricted unit (b) $28.89 -- $28.89 Number of restricted units remaining available for future issuance under the Restricted Unit Plans (excluding securities reflected in column (a)) (c) 1,249,457 -- 1,249,457 Plan Category Equity compensation plans approved by security holders (1) Equity compensation plans not approved by security holders Total (1) Relates to the Restricted Unit Plans. (2) Represents number of restricted units that, as of September 26, 2009, had been granted under the 2000 Restricted Unit Plan but had not yet vested. No restricted units have yet been granted under the 2009 Restricted Unit Plan. 98 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: 1. Within the past three years, the Supervisor: a. has not been employed by the Partnership and has not received more than $100,000 per year in direct compensation from the Partnership, other than Supervisor and committee fees and pension or other forms of deferred compensation for prior service; b. has not provided significant advisory or consultancy services to the Partnership, and has not been affiliated with a company or a firm that has provided such services to the Partnership in return for aggregate payments during any of the last three fiscal years of the Partnership in excess of the greater of 2% of the other company’s consolidated gross revenues or $1 million; c. has not been a significant customer or supplier of the Partnership and has not been affiliated with a company or firm that has been a customer or supplier of the Partnership and has either made to the Partnership or received from the Partnership payments during any of the last three fiscal years of the Partnership in excess of the greater of 2% of the other company’s consolidated gross revenues or $1 million; d. has not been employed by or affiliated with an internal or external auditor that within the past three years provided services to the Partnership; and e. has not been employed by another company where any of the Partnership’s current executives serve on that company’s compensation committee; 2. The Supervisor is not a spouse, parent, sibling, child, mother- or father-in-law, son- or daughter-in-law or brother- or sister-in-law of a person having a relationship described in 1. above nor shares a residence with such person; 3. The Supervisor is not affiliated with a tax-exempt entity that within the past 12 months received significant contributions from the Partnership (contributions of the greater of 2% of the entity’s consolidated gross revenues or $1 million are considered significant); and 4. The Supervisor does not have any other relationships with the Partnership or with members of senior management of the Partnership that the Board determines to be material. 99 ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES The following table sets forth the aggregate fees for services related to fiscal years 2009 and 2008 provided by PricewaterhouseCoopers LLP, our independent registered public accounting firm. Audit Fees (a) Audit-Related Fees (b) Tax Fees (c) All Other Fees (d) Fiscal 2009 Fiscal 2008 $ 2,265,000 - 840,030 1,605 $ 2,325,000 84,000 722,000 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) Audit-Related Fees consist of professional services rendered in connection with acquisition-related due diligence and consultations concerning financial accounting and reporting standards. (c) Tax Fees consist of fees for professional services related to tax reporting, tax compliance and transaction services assistance. (d) All Other Fees represent fees for 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 2009 and fiscal 2008. 100 PART IV ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES (a) The following documents are filed as part of this Annual Report: 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. 101 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. SIGNATURES Date: November 25, 2009 SUBURBAN PROPANE PARTNERS, L.P. 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 25, 2009 By: /s/ HAROLD R. LOGAN, JR. Chairman and Supervisor November 25, 2009 (Harold R. Logan, Jr.) By: /s/ JOHN HOYT STOOKEY Supervisor November 25, 2009 (John Hoyt Stookey) By: /s/ DUDLEY C. MECUM (Dudley C. Mecum) By: /s/ JOHN D. COLLINS (John D. Collins) By: /s/ JANE SWIFT (Jane Swift) Supervisor Supervisor Supervisor November 25, 2009 November 25, 2009 November 25, 2009 By: /s/ MICHAEL A. STIVALA Chief Financial Officer November 25, 2009 (Michael A. Stivala) By /s/ MICHAEL A. KUGLIN Controller and Chief Accounting Officer November 25, 2009 (Michael A. Kuglin) 102 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. INDEX TO EXHIBITS Exhibit Number 2.1 3.1 3.2 3.3 3.4 4.1 4.2 4.3 4.4 10.1 Description Exchange Agreement dated as of July 27, 2006 by and among the Partnership, the Operating Partnership and the General Partner. (Incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed July 28, 2006). 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). 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). 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). 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). 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). Indenture, dated as of December 23, 2003, between Suburban Propane Partners, L.P., Suburban Energy Finance Corp. and The Bank of New York, as Trustee (including Form of Senior Global Exchange Note). (Incorporated by reference to Exhibit 10.28 to the Partnership’s Quarterly Report on Form 10-Q for the fiscal quarter ended December 27, 2003). Exchange and Registration Rights Agreement, dated December 23, 2003 among Suburban Propane Partners, L.P., Suburban Energy Finance Corp., Wachovia Capital Markets, LLC and Goldman, Sachs & Co. (Incorporated by reference to Exhibit 4.1 to the Partnership’s Registration Statement on Form S-4 dated December 19, 2003). Exchange and Registration Rights Agreement, dated March 31, 2005 among Suburban Propane Partners, L.P., Suburban Energy Finance Corp., Wachovia Capital Markets, LLC and Goldman, Sachs & Co. (Incorporated by reference to Exhibit 4.1 to the Partnership’s Current Report on Form 8-K filed April 1, 2005). Agreement between Mark A. Alexander and the Partnership, dated April 22, 2009. (Incorporated by reference to Exhibit 10.1 to the Partnership’s Quarterly Report on Form 10- Q filed August 6, 2009). E-1  10.5 10.6 10.7 10.8 10.9 10.10 10.11 10.12 10.13 10.14 10.15 21.1 23.1 31.1 31.2 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). 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. (Filed herewith). 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). Suburban Propane, L.P. Severance Protection Plan, as amended on January 24, 2008, January 20, 2009 and November 10, 2009. (Filed herewith). 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). Amended and Restated Supplemental Executive Retirement Plan of the Partnership (effective as of January 1, 1998). (Incorporated by reference to Exhibit 10.23 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 29, 2001). 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). 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). 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). 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). 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). Subsidiaries of Suburban Propane Partners, L.P. (Filed herewith). Consent of PricewaterhouseCoopers LLP. (Filed herewith). Certification of the President and Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. (Filed herewith). Certification of the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. (Filed herewith). E-2  32.1 32.2 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). 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 Five-Year Performance Graph (Filed herewith). E-3 INDEX TO FINANCIAL STATEMENTS SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES Page Report of Independent Registered Public Accounting Firm.......................................................................…... F-2 Consolidated Balance Sheets – As of September 26, 2009 and September 27, 2008......................................................................................... F-3 Consolidated Statements of Operations – Years Ended September 26, 2009, September 27, 2008 and September 29, 2007...….................................. F-4 Consolidated Statements of Cash Flows – Years Ended September 26, 2009, September 27, 2008 and September 29, 2007......................................... F-5 Consolidated Statements of Partners’ Capital – Years Ended September 26, 2009, September 27, 2008 and September 29, 2007......................................... F-6 Notes to Consolidated Financial Statements........................…............................................................................. F-7 F-1 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 statement of operations, partners' capital and of cash flows present fairly, in all material respects, the financial position of Suburban Propane Partners, L.P. and its subsidiaries at September 26, 2009 and September 27, 2008, and the results of their operations and their cash flows for each of the three years in the period ended September 26, 2009 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 accompanying index 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 26, 2009, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership's management is responsible for these financial statements and financial statement schedules, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in 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. 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. PricewaterhouseCoopers LLP Florham Park, New Jersey November 25, 2009 F-2 SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (in thousands) ASSETS Current assets: Cash and cash equivalents Accounts receivable, less allowance for doubtful accounts of $4,374 and $6,578, respectively Inventories Other current assets Total current assets Property, plant and equipment, net Goodwill Other intangible assets, net Other assets Total assets LIABILITIES AND PARTNERS' CAPITAL Current liabilities: Accounts payable Accrued employment and benefit costs Accrued insurance Customer deposits and advances Accrued interest Other current liabilities Total current liabilities Long-term borrowings Accrued insurance Other liabilities Total liabilities Commitments and contingencies September 26, 2009 September 27, 2008 $ 163,173 $ 137,698 52,035 70,158 22,190 307,556 357,187 274,897 13,798 24,076 977,514 $ $ 35,677 40,875 10,410 65,769 7,294 20,034 180,059 349,415 41,838 46,485 617,797 94,933 79,822 47,098 359,551 367,808 276,282 16,018 16,054 1,035,713 $ $ 58,079 27,053 41,120 71,206 11,030 17,568 226,056 531,772 31,913 25,896 815,637 Partners' capital: Common Unitholders (35,228 and 32,725 units issued and outstanding at September 26, 2009 and September 27, 2008, respectively) Accumulated other comprehensive loss Total partners' capital Total liabilities and partners' capital 421,005 (61,288) 359,717 977,514 $ 264,231 (44,155) 220,076 1,035,713 $ 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) Revenues Propane Fuel oil and refined fuels Natural gas and electricity All other Costs and expenses Cost of products sold Operating General and administrative Restructuring charges and severance costs Depreciation and amortization Income before loss on debt extinguishment, interest expense and provision for income taxes Loss on debt extinguishment Interest income Interest expense Income before provision for income taxes Provision for income taxes Income from continuing operations Discontinued operations: Gain on disposal of discontinued operations Income from discontinued operations September 26, 2009 Year Ended September 27, 2008 September 29, 2007 $ 864,012 159,596 76,832 42,714 1,143,154 $ 1,132,950 288,078 103,745 49,390 1,574,163 $ 1,019,798 262,076 94,352 63,337 1,439,563 540,385 304,767 57,044 - 30,343 932,539 210,615 (4,624) 802 (39,069) 167,724 2,486 1,039,436 308,071 48,134 - 28,394 1,424,035 150,128 - 2,787 (39,839) 113,076 1,903 865,418 322,852 56,422 1,485 28,790 1,274,967 164,596 - 3,863 (39,459) 129,000 5,653 165,238 111,173 123,347 - - 43,707 - 1,887 2,053 Net income $ 165,238 $ 154,880 $ 127,287 Income per Common Unit - basic Income from continuing operations Discontinued operations Net income Weighted average number of Common Units outstanding - basic Income per Common Unit - diluted Income from continuing operations Discontinued operations Net income Weighted average number of Common Units outstanding - diluted $ $ $ $ $ $ 4.99 - 4.99 33,134 4.96 - 4.96 33,315 3.39 1.33 4.72 32,783 3.37 1.33 4.70 32,950 $ $ $ $ $ $ 3.79 0.12 3.91 32,554 3.77 0.12 3.89 32,730 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) Cash flows from operating activities: Net income Adjustments to reconcile net income to net cash provided by operations: Depreciation and amortization expense Depreciation expense - discontinued operations Amortization of debt origination costs Compensation cost recognized under Restricted Unit Plan Amortization of discount on long-term borrowings Gain on disposal of property, plant and equipment, net Gain on disposal of discontinued operations Pension settlement charge Loss on debt extinguishment Deferred tax provision Changes in assets and liabilities Decrease (increase) in accounts receivable Decrease (increase) in inventories Decrease (increase) in prepaid expenses and other current assets (Decrease) increase in accounts payable Increase (decrease) in accrued employment and benefit costs (Decrease) increase in accrued insurance (Decrease) increase in customer deposits and advances (Decrease) increase in accrued interest Increase (decrease) in other accrued liabilities (Increase) decrease in other noncurrent assets Increase (decrease) in other noncurrent liabilities Contribution to defined benefit pension plan Net cash provided by operating activities Cash flows from investing activities: Capital expenditures Proceeds from sale of property, plant and equipment Proceeds from sale of discontinued operations Net cash (used in) provided by investing activities Cash flows from financing activities: Repayments of long-term borrowings (includes premium and fees) Proceeds from long-term borrowings Issuance costs associated with long-term borrowings Repayments of short-term borrowings Net proceeds from issuance of Common Units Partnership distributions Net cash (used in) financing activities Net increase in cash and cash equivalents Cash and cash equivalents at beginning of year Cash and cash equivalents at end of year September 26, 2009 Year Ended September 27, 2008 September 29, 2007 $ 165,238 $ 154,880 $ 127,287 30,343 - 1,923 2,396 226 (650) - - 4,624 1,385 42,898 9,664 24,908 (22,402) 13,822 (20,785) (5,437) (3,736) 4,466 (5,787) 3,455 - 246,551 (21,837) 4,985 - (16,852) 28,394 - 1,328 2,156 234 (2,252) (43,707) - - 1,277 (9,663) 1,424 (26,935) 1,080 (10,587) 27,240 (4,188) 2,484 5,307 2,810 (10,765) - 120,517 (21,819) 4,734 53,715 36,630 28,790 452 1,327 3,014 234 (2,782) (1,887) 3,269 - 3,800 (6,827) (1,915) (3,658) (448) 3,551 6,520 12,780 175 (5,475) (41,120) 43,870 (25,000) 145,957 (26,756) 5,783 1,284 (19,689) (177,821) 100,000 (5,543) (110,000) 95,880 (106,740) (204,224) 25,475 137,698 163,173 $ (15,000) - - - - (101,035) (116,035) 41,112 96,586 137,698 $ - - - - - (90,253) (90,253) 36,015 60,571 96,586 $ Supplemental disclosure of cash flow information: Cash paid for interest $ 39,153 $ 35,217 $ 37,165 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) Number of Common Units Common Unitholders General Partner Deferred Compen- sation Common Units Held in Trust Accumulated Other Compre- hensive (Loss) Income Total Partners' Capital Comprehensive Income (Loss) Balance at September 30, 2006 30,314 $ 170,151 $ (1,969) $ 5,704 $ (5,704) $ (67,481) $ 100,701 127,287 127,287 $ 127,287 (173) (173) (173) Net income Other comprehensive income: Net unrealized losses on cash flow hedges Reclassification of realized losses on cash flow hedges into earnings Non-cash pension settlement charge Minimum pension liability adjustment Adjustment to initially adopt new benefits accounting standard Total comprehensive income Partnership distributions Common Units issued under Restricted Unit Plan Common Units issued in Exchange of GP interest Exchange and cancellation of GP Interest Common Units distributed from trust Compensation cost recognized under Restricted Unit Plan, net of forfeitures 60 2,300 (90,253) 80,443 (82,412) 1,969 3,014 (44) 44 1,967 3,269 63,510 - $ 195,860 1,967 3,269 63,510 (43,045) 1,967 3,269 63,510 (43,045) (90,253) 80,443 (80,443) - 3,014 Balance at September 29, 2007 32,674 $ 208,230 $ - $ 5,660 $ (5,660) $ (41,953) $ 166,277 Net income Other comprehensive income: Net unrealized losses on cash flow hedges Reclassification of realized gains on cash flow hedges into earnings Amortization of net actuarial losses and prior service credits into earnings and net change in funded status of benefit plans Total comprehensive income Partnership distributions Common Units issued under Restricted Unit Plan Common Units distributed from trust Compensation cost recognized under Restricted Unit Plan, net of forfeitures 154,880 154,880 $ 154,880 (101,035) 51 2,156 (5,660) 5,660 (2,916) (2,916) (1,377) (1,377) (2,916) (1,377) 2,091 2,091 $ 2,091 152,678 (101,035) - 2,156 Balance at September 27, 2008 32,725 $ 264,231 $ - $ - $ - $ (44,155) $ 220,076 Net income Other comprehensive income: Net unrealized losses on cash flow hedges Amortization of net actuarial losses and prior service credits into earnings and net change in funded status of benefit plans Total comprehensive income Partnership distributions Common Units issued under Restricted Unit Plan Sale of Common Units under public offering, net of offering expenses Compensation cost recognized under Restricted Unit Plan, net of forfeitures 165,238 165,238 $ 165,238 (106,740) 72 2,431 95,880 2,396 (991) (991) (991) (16,142) (16,142) $ (16,142) 148,105 (106,740) 95,880 2,396 Balance at September 26, 2009 35,228 $ 421,005 $ - $ - $ - $ (61,288) $ 359,717 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 35,227,954 Common Units outstanding at September 26, 2009. The holders of Common Units are entitled to participate in distributions and exercise the rights and privileges available to limited partners under the Third Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”), adopted on October 19, 2006 following approval by Common Unitholders at the Partnership’s Tri-Annual Meeting and as thereafter amended by the Board of Supervisors on July 31, 2007, pursuant to the authority granted to the Board in the Partnership Agreement. Rights and privileges under the Partnership Agreement include, among other things, the election of all members of the Board of Supervisors and voting on the removal of the general partner. Suburban Propane, L.P. (the “Operating Partnership”), a Delaware limited partnership, is the Partnership’s operating subsidiary formed to operate the propane business and assets. In addition, Suburban Sales & Service, Inc. (the “Service Company”), a subsidiary of the Operating Partnership, was formed to operate the service work and appliance and parts businesses of the Partnership. The Operating Partnership, together with its direct and indirect subsidiaries, accounts for substantially all of the Partnership’s assets, revenues and earnings. The Partnership, the Operating Partnership and the Service Company commenced operations in March 1996 in connection with the Partnership’s initial public offering. The general partner of both the Partnership and the Operating Partnership is Suburban Energy Services Group LLC (the “General Partner”), a Delaware limited liability company. On October 19, 2006, the Partnership consummated an agreement with its General Partner to exchange 2,300,000 newly issued Common Units for the General Partner’s incentive distribution rights (“IDRs”) and the economic interest in the Partnership and the Operating Partnership included in the general partner interests therein (the “GP Exchange Transaction”). Prior to the GP Exchange Transaction, the General Partner was majority-owned by senior management of the Partnership and owned 224,625 general partner units (an approximate 0.74% ownership interest) in the Partnership and a 1.0101% general partner interest in the Operating Partnership. The General Partner also held all outstanding IDRs and appointed two members to the Board of Supervisors. As a result of the GP Exchange Transaction, the General Partner no longer has any economic interest in either the Partnership or the Operating Partnership other than as a holder of 784 Common Units that will remain in the General Partner, no IDRs are outstanding and the sole member of the General Partner is the Partnership’s Chief Executive Officer. During fiscal 2004, the Partnership acquired substantially all of the assets and operations of Agway Energy Products, LLC, Agway Energy Services, Inc. and Agway Energy Services PA, Inc. (collectively referred to as “Agway Energy”). The operations of Agway Energy consisted of the distribution and marketing of propane, fuel oil and refined fuels, as well as the marketing of natural gas and electricity. The Partnership’s fuel oil and refined fuels, natural gas and electricity and services businesses are structured as corporate entities (collectively referred to as “Corporate Entities”) and, as such, are subject to corporate level income tax. Suburban Energy Finance Corporation, a direct wholly-owned subsidiary of the Partnership, was formed on November 26, 2003 to serve as co-issuer, jointly and severally with the Partnership, of the Partnership’s 6.875% senior notes due in 2013. F-7 The Partnership serves approximately 850,000 active residential, commercial, industrial and agricultural customers from approximately 300 locations in 30 states. The Partnership’s operations are concentrated in the east and west coast regions of the United States, including Alaska. No single customer accounted for 10% or more of the Partnership’s revenues during fiscal 2009, 2008 or 2007. 2. Summary of Significant Accounting Policies Principles of Consolidation. The consolidated financial statements include the accounts of the Partnership, the Operating Partnership and all of its direct and indirect subsidiaries. All significant intercompany transactions and account balances have been eliminated. As a result of the GP Exchange Transaction, the General Partner no longer has any economic interest in the Partnership or the Operating Partnership apart from 784 Common Units held by it. The Partnership consolidates the results of operations, financial condition and cash flows of the Operating Partnership as a result of the Partnership’s 100% limited partner interest in the Operating Partnership. Fiscal Period. The Partnership’s fiscal year ends on the last Saturday nearest to September 30. Revenue Recognition. Sales of propane, fuel oil and refined fuels are recognized at the time product is delivered to the customer. Revenue from the sale of appliances and equipment is recognized at the time of sale or when installation is complete, as applicable. Revenue from repairs, maintenance and other service activities is recognized upon completion of the service. Revenue from service contracts is recognized ratably over the service period. Revenue from the natural gas and electricity business is recognized based on customer usage as determined by meter readings, as adjusted for amounts delivered but unbilled at the end of each accounting period. 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. On September 28, 2008, the Partnership adopted new accounting guidance on 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. Adoption of this new accounting guidance did not impact the Partnership’s financial position, results of operations or cash flows. 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. The Partnership measures the fair value of its options and futures derivative instruments using Level 1 inputs and the fair value of its interest rate swap using Level 2 inputs. See Derivative Instruments and Hedging Activities, below, for additional information regarding fair value measurements. Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates have been made by F-8 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. 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. On December 28, 2008, the Partnership adopted new accounting guidance on disclosures about derivative instruments and hedging activities, which required enhanced disclosures about an entity’s objectives for using derivative instruments (defined below) and related hedged items, how those derivative instruments are accounted for and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. Commodity Price Risk. Given the retail nature of its operations, the Partnership maintains a certain level of priced physical inventory to ensure its field operations have adequate supply commensurate with the time of year. The Partnership’s strategy is to keep its physical inventory priced relatively close to market for its field operations. The Partnership enters into a combination of exchange-traded futures and option contracts, forward contracts and, in certain instances, over-the-counter option contracts (collectively, “derivative instruments”) to hedge price risk associated with propane and fuel oil physical inventory, as well as future purchases of propane or fuel oil used in its operations and to ensure adequate supply during periods of high demand. Under this risk management strategy, realized gains or losses on derivative instruments will typically offset losses or gains on the physical inventory once the product is sold. All of the Partnership’s derivative instruments are reported on the consolidated balance sheet 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, forward and option contracts are entered into, other than those designated as normal purchases or normal sales, the Partnership makes a determination as to whether the derivative instrument qualifies for designation as a hedge. Changes in the fair value of derivative instruments are recorded each period in current period earnings or other comprehensive income (loss) (“OCI”), depending on whether the derivative instrument is designated as a hedge and, if so, the type of hedge. For derivative instruments designated as cash flow hedges, the Partnership formally assesses, both at the hedge contract’s inception and on an ongoing basis, whether the hedge contract is highly effective in offsetting changes in cash flows of hedged items. Changes in the fair value of derivative instruments designated as cash flow hedges are reported in OCI to the extent effective and reclassified into cost of products sold during the same period in which the hedged item affects earnings. The mark-to-market gains or losses on ineffective portions of cash flow hedges used to hedge future purchases are recognized in cost of products sold immediately. Changes in the fair value of derivative instruments that are not designated as cash flow hedges, and that do not meet the normal purchase and normal sale exemption, are recorded within cost of products sold as they occur. Cash flows associated with derivative instruments are F-9 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 ½ 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. Changes in the fair value of the interest rate swaps are recognized in OCI until the hedged items are 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. 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 Building and land improvements Transportation equipment Storage facilities Office equipment Tanks and cylinders Computer software 40 Years 20-40 Years 4-20 Years 7-40 Years 5-10 Years 15-40 Years 3-7 Years The weighted average estimated useful life of the Partnership’s tanks and cylinders is approximately 25 years. The Partnership reviews the recoverability of long-lived assets when circumstances occur that indicate that the carrying value of an asset may not be recoverable. Such circumstances include a significant adverse change in the manner in which an asset is being used, current operating losses combined with a history of operating losses experienced by the asset or a current expectation that an asset will be sold or otherwise disposed of before the end of its previously estimated useful life. Evaluation of possible impairment is based on the Partnership’s ability to recover the value of the asset from the future undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the expected undiscounted cash flows are less than the carrying amount of such asset, an impairment loss is recorded as the amount by which the carrying amount of an asset exceeds its fair value. The fair value of an asset will be measured using the best information available, including prices for similar assets or the result of using a discounted cash flow valuation technique. Goodwill. Goodwill represents the excess of the purchase price over the fair value of net assets acquired. Goodwill is subject to an impairment review at a reporting unit level, on an annual basis in August of each year, or when an event occurs or circumstances change that would indicate potential impairment. The Partnership assesses the carrying value of goodwill at a reporting unit level based on an estimate of the fair value of the respective reporting unit. Fair value of the reporting unit is estimated using discounted cash flow analyses taking into consideration estimated cash flows in a ten-year projection period and a terminal value calculation at the end of F-10 the projection period. If the fair value of the reporting unit exceeds its carrying value, the goodwill associated with the reporting unit is not considered to be impaired. If the carrying value of the reporting unit exceeds its fair value, an impairment loss is recognized to the extent that the carrying amount of the associated goodwill, if any, exceeds the implied fair value of the goodwill. Other Intangible Assets. Other intangible assets consist of customer lists, tradenames, non-compete agreements and leasehold interests. Customer lists and tradenames are amortized under the straight-line method over the estimated period for which the assets are expected to contribute to the future cash flows of the reporting entities to which they relate, ending periodically between fiscal years 2012 and 2019. Non-compete agreements are amortized under the straight-line method over the periods of the related agreements, which ended in fiscal year 2009. Leasehold interests are amortized under the straight-line method over the shorter of the lease term or the useful life of the related assets, through fiscal 2025. Accrued Insurance. Accrued insurance represents the estimated costs of known and anticipated or unasserted claims for self-insured liabilities related to general and product, workers’ compensation and automobile liability. Accrued insurance provisions for unasserted claims arising from unreported incidents are based on an analysis of historical claims data. For each claim, the Partnership records a provision up to the estimated amount of the probable claim utilizing actuarially determined loss development factors applied to actual claims data. The Partnership maintains insurance coverage such that its net exposure for insured claims is limited to the insurance deductible, claims above which are paid by the Partnership’s insurance carriers. For the portion of the estimated liability that exceeds insurance deductibles, the Partnership records an asset related to the amount of the liability expected to be covered by insurance. Claims are generally settled within five years of origination. Customer Deposits and Advances. The Partnership offers different payment programs to its customers including the ability to prepay for usage and to make equal monthly payments on account under a budget payment plan. The Partnership establishes a liability within customer deposits and advances for amounts collected in advance of deliveries. Income Taxes. As discussed in Note 1, the Partnership structure consists of two limited partnerships, the Partnership and the Operating Partnership, and several Corporate Entities. For federal income tax purposes, as well as for state income tax purposes in the majority of the states in which the Partnership operates, the earnings attributable to the Partnership and the Operating Partnership are included in the tax returns of the individual partners. As a result, except for certain states that impose an income tax on partnerships, no income tax expense is reflected in the Partnership’s consolidated financial statements relating to the earnings of the Partnership and the Operating Partnership. The earnings attributable to the Corporate Entities are subject to federal and state income taxes. Net earnings for financial statement purposes may differ significantly from taxable income reportable to Common Unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under the Partnership Agreement. Income taxes for the Corporate Entities are provided based on the asset and liability approach to accounting for income taxes. Under this method, deferred tax assets and liabilities are recognized for the expected future tax consequences of differences between the carrying amounts and the tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period when the change is enacted. A valuation allowance is recorded to reduce the carrying amounts of deferred tax assets when it is more likely than not that the full amount will not be realized. Asset Retirement Obligations. 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, except for certain obligations of lessees. 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. F-11 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. 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 derivative instruments that are not designated as cash flow hedges are recorded in each reporting period within cost of products sold. Cost of products sold is reported exclusive of any depreciation and amortization as such amounts are reported separately within the consolidated statements of operations. All other costs of operating the Partnership’s retail propane, fuel oil and refined fuels distribution and appliance sales and service operations, as well as the natural gas and electricity marketing business, are reported within operating expenses in the consolidated statements of operations. These operating expenses include the compensation and benefits of field and direct operating support personnel, costs of operating and maintaining the vehicle fleet, overhead and other costs of the purchasing, training and safety departments and other direct and indirect costs of operating the Partnership’s customer service centers. All costs of back office support functions, including compensation and benefits for executives and other support functions, as well as other costs and expenses to maintain finance and accounting, treasury, legal, human resources, corporate development and the information systems functions are reported within general and administrative expenses in the consolidated statements of operations. Net Income Per Unit. Subsequent to the GP Exchange Transaction, computations of basic income per Common Unit are performed by dividing net income 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 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 the Restricted Unit Plans. Prior to the GP Exchange Transaction, when the General Partner’s interest included IDRs in the Partnership, computations of earnings per Common Unit were performed, when applicable, using the two-class method when participating securities existed. The two-class method is an earnings allocation formula that computes earnings per unit for each class of Common Unit and participating security according to distributions declared and the participating rights in undistributed earnings, as if all of the earnings were distributed to the limited partners and the General Partner (inclusive of the IDRs of the General Partner which were considered participating securities for purposes of the two-class method). Net income was allocated to the Common Unitholders and the General Partner in accordance with their respective Partnership ownership interests, after giving effect to any priority income allocations for incentive distributions allocated to the General Partner. For purposes of the computation of income per Common Unit for the year ended September 29, 2007, earnings that would have been allocated to the General Partner for the period prior to the GP Exchange Transaction were not significant. Following the GP Exchange Transaction F-12 consummated on October 19, 2006, the two-class method of computing income per Common Unit was no longer applicable. In computing diluted net income per Common Unit, weighted average units outstanding used to compute basic net income per Common Unit were increased by 180,789, 166,308 and 175,701 units for the years ended September 26, 2009, September 27, 2008 and September 29, 2007, respectively, to reflect the potential dilutive effect of the unvested restricted units outstanding using the treasury stock method. Comprehensive Income. The Partnership reports comprehensive (loss) income (the total of net income and all other non-owner changes in partners’ capital) within the consolidated statement of partners’ capital. Comprehensive (loss) income includes unrealized gains and losses on derivative instruments accounted for as cash flow hedges, minimum pension liability adjustments and changes in the funded status of pension and other postretirement benefit plans. Recently Issued Accounting Standards. In December 2008, the Financial Accounting Standards Board (“FASB”) issued new financial reporting guidance to require more detailed disclosures about employers’ pension plan assets. These new disclosures will include more information on investment strategies, major categories of plan assets, concentrations of risk within plan assets and valuation techniques used to measure the fair value of plan assets. The new guidance is effective for fiscal years ending after December 15, 2009, which will be the Partnership’s 2010 fiscal year ending September 25, 2010. Since it only addresses disclosures, the adoption of the new guidance is not expected to have an impact on the Partnership’s consolidated financial position, results of operations or cash flows. In December 2007, the FASB issued revised accounting guidance concerning business combinations. Among other things, this revised guidance requires an entity to recognize acquired assets, liabilities assumed and any noncontrolling interest at their respective fair values as of the acquisition date, clarifies how goodwill involved in a business combination is to be recognized and measured, as well as requires the expensing of acquisition-related costs as incurred. Most of its provisions are effective for business combinations entered into in fiscal years beginning on or after December 15, 2008, which will be the Partnership’s 2010 fiscal year beginning September 27, 2009, with early adoption prohibited. Certain provisions, in particular a provision related to the accounting for acquired tax benefits, are required to be applied in future fiscal years regardless of when the business combination occurred. To the extent the Partnership’s Corporate Entities generate taxable profits in future years that enable the utilization of tax benefits acquired in the Agway Energy acquisition, the corresponding reduction in the valuation allowance will be recorded as a reduction in the provision for income taxes. Reclassifications. Certain prior period amounts have been reclassified to conform with the current period presentation. In addition, other current liabilities were increased and other liabilities were reduced as of September 27, 2008 by $2,441 to reclassify the current portion of the interest rate swap liability. Subsequent Events. The Partnership has evaluated all subsequent events that occurred after the balance sheet date through November 25, 2009, 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. F-13 Prior to October 19, 2006, the General Partner had IDRs which represented an incentive for the General Partner to increase distributions to Common Unitholders in excess of the target quarterly distribution of $0.55 per Common Unit. With regard to the first $0.55 of quarterly distributions paid in any given quarter, 98.26% of the Available Cash was distributed to the Common Unitholders and 1.74% was distributed to the General Partner. With regard to the balance of quarterly distributions in excess of the $0.55 per Common Unit target distribution, 85% of the Available Cash was distributed to the Common Unitholders and 15% was distributed to the General Partner. As a result of the GP Exchange Transaction, the IDRs were cancelled and the General Partner is no longer entitled to receive any cash distributions in respect of its general partner interests. Accordingly, beginning with the quarterly distribution paid on November 14, 2006 in respect of the fourth quarter of fiscal 2006, 100% of all cash distributions are paid to holders of Common Units. The following summarizes the quarterly distributions per Common Unit declared and paid in respect of each of the quarters in the three fiscal years in the period ended September 26, 2009: First Quarter Second Quarter Third Quarter Fourth Quarter Fiscal 2009 Fiscal 2008 Fiscal 2007 $ 0.8100 0.8150 0.8250 0.8300 $ 0.7625 0.7750 0.8000 0.8050 $ 0.6875 0.7000 0.7125 0.7500 On October 22, 2009, the Board of Supervisors declared a quarterly distribution of $0.830 per Common Unit, or $3.32 per Common Unit on an annualized basis, in respect of the fourth quarter of fiscal 2009, which was paid on November 10, 2009 to holders of record on November 3, 2009. This quarterly distribution included an increase of $0.005 per Common Unit, or $0.02 per Common Unit on an annualized basis, from the previous distribution rate established in July, 2009, and an increase of $0.0250 per Common Unit, or $0.10 per Common Unit on an annualized basis, from the prior year-end distribution rate. 4. Selected Balance Sheet Information Inventories consist of the following: Propane and refined fuels Natural gas Appliances and related parts As of September 26, 2009 September 27, 2008 $ $ 67,293 219 2,646 70,158 76,036 283 3,503 79,822 $ $ 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. F-14 Property, plant and equipment consist of the following: As of September 26, 2009 September 27, 2008 Land and improvements Buildings and improvements Transportation equipment Storage facilities Equipment, primarily tanks and cylinders Computer systems Construction in progress Less: accumulated depreciation $ $ 28,452 78,189 33,231 76,594 471,787 43,538 2,657 734,448 377,261 357,187 28,307 77,833 35,033 74,954 463,332 41,796 1,711 722,966 355,158 367,808 $ $ Depreciation expense from continuing operations for the years ended September 26, 2009, September 27, 2008 and September 29, 2007 amounted to $28,123, $26,170 and $26,547, respectively. Depreciation expense from discontinued operations for the years ended September 26, 2009, September 27, 2008 and September 29, 2007 amounted to $-0-, $-0- and $452, respectively. 5. Goodwill and Other Intangible Assets The Partnership’s fiscal 2009 and fiscal 2008 annual goodwill impairment review resulted in no adjustments to the carrying amount of goodwill. During fiscal 2009 and fiscal 2008, the Partnership reversed $1,385 and $1,277 of the deferred tax asset valuation allowance, respectively, which was established through purchase accounting for the Agway Acquisition, as a reduction to goodwill. This adjustment resulted from the utilization of a portion of the net operating losses established in purchase accounting for the Agway Acquisition. The carrying value of goodwill assigned to the Partnership’s operating segments are as follows: As of September 26, 2009 September 27, 2008 $ $ 262,559 4,438 7,900 274,897 262,559 5,823 7,900 276,282 $ $ Propane Fuel oil and refined fuels Natural gas and electricity F-15 Other intangible assets, the majority of which were acquired in the Agway Acquisition, consist of the following: Customer lists Tradenames Other Less: accumulated amortization Customer lists Tradenames Other As of September 26, 2009 September 27, 2008 $ 22,316 1,499 1,967 25,782 $ 22,316 1,499 2,117 25,932 (10,596) (862) (526) (11,984) 13,798 $ (8,632) (712) (570) (9,914) 16,018 $ Aggregate amortization expense related to other intangible assets for the years ended September 26, 2009, September 27, 2008 and September 29, 2007 was $2,220, $2,224 and $2,243, respectively. Aggregate amortization expense related to other intangible assets for each of the five succeeding fiscal years as of September 26, 2009 is as follows: 2010 - $2,205; 2011 - $2,205; 2012 - $1,730; 2013 - $1,572 and 2014 - $1,237. 6. Restructuring Charges and Severance Costs During fiscal 2007, payments for severance and other employee costs associated with a previously approved and initiated plan of reorganization totaled $1,621 and were charged against the reserves established. As of September 29, 2007, the reserve for severance and other employee benefits was fully utilized. For the years ended September 26, 2009 and September 27, 2008, the Partnership did not record any restructuring charges. For the year ended September 29, 2007, the Partnership incurred severance charges of $1,485 associated with positions eliminated during fiscal 2007 unrelated to a specific plan of restructuring. 7. Income Taxes For federal income tax purposes, as well as for state income tax purposes in the majority of the states in which the Partnership operates, the earnings attributable to the Partnership, as a separate legal entity, and the Operating Partnership are not subject to income tax at the partnership level. Rather, the taxable income or loss attributable to the Partnership, as a separate legal entity, and to the Operating Partnership, which may vary substantially from the income (loss) before income taxes reported by the Partnership in the consolidated statement of operations, are includable in the federal and state income tax returns of the individual partners. The aggregate difference in the basis of the Partnership’s net assets for financial and tax reporting purposes cannot be readily determined as the Partnership does not have access to information regarding each partner’s basis in the Partnership. The earnings of the Corporate Entities that do not qualify under the Internal Revenue Code for partnership status are subject to federal and state income taxes. The Partnership’s fuel oil and refined fuels, natural gas and electricity and services business segments are structured as corporate entities and, as such, are subject to corporate level income tax. However, a number of those corporate entities have experienced operating losses in recent years and, as a result, a full valuation allowance has been provided against the deferred tax assets. As a result, at present, many of those Corporate Entities do not report a tax provision. The conclusion that a full valuation allowance is necessary was based upon an analysis of all available evidence, both negative and positive at F-16 the balance sheet date, which, taken as a whole, indicates that it is more likely than not that sufficient future taxable income will not be available to utilize the Partnership’s deferred tax assets. Management’s periodic reviews include, among other things, the nature and amount of the taxable income and expense items, the expected timing when assets will be used or liabilities will be required to be reported and the reliability of historical profitability of businesses expected to provide future earnings. Furthermore, management considered tax-planning strategies it could use to increase the likelihood that the deferred tax assets will be realized. The income tax provision of all the legal entities included in the Partnership’s consolidated statement of operations consists of the following: September 26, 2009 Year Ended September 27, 2008 September 29, 2007 Current Federal State and local Deferred $ $ $ 173 928 1,101 1,385 2,486 73 553 626 1,277 1,903 474 1,379 1,853 3,800 5,653 $ $ $ As a result of the calendar year 2009, 2008 and 2007 projected profitability of the Partnership’s Corporate Entities, the Partnership reported taxable income and, as a result, utilized net operating losses to offset the current cash tax liability. Utilization of these net operating losses resulted in a deferred tax provision of $1,385, $1,277 and $3,800 in fiscal 2009, 2008 and 2007, respectively, and a corresponding reversal of a portion of the valuation allowance established in purchase accounting for the acquisition of Agway Energy, which reduced goodwill. The provision for income taxes differs from income taxes computed at the United States federal statutory rate as a result of the following: Income tax provision at federal statutory tax rate Impact of Partnership income not subject to federal income taxes Permanent differences Change in valuation allowance State income taxes Alternative minimum tax Other, net Provision for income taxes - current and deferred September 26, 2009 Year Ended September 27, 2008 September 29, 2007 $ 58,704 $ 39,577 $ 45,149 (56,294) 719 (2,048) 1,262 143 - 2,486 $ (45,323) 1,240 6,930 (572) 53 (2) 1,903 $ (39,459) (358) (1,583) 1,379 447 78 5,653 $ F-17 The components of net deferred taxes and the related valuation allowance using current enacted tax rates are as follows: Deferred tax assets: Net operating loss carryforwards Allowance for doubtful accounts Inventory Intangible assets Deferred revenue Derivative instruments AMT credit carryforward Other accruals Total deferred tax assets Deferred tax liabilities: Derivative instruments Property, plant and equipment Total deferred tax liabilities Net deferred tax assets Valuation allowance Net deferred tax assets As of September 26, 2009 September 27, 2008 $ 38,995 679 833 1,523 1,613 - 789 2,915 47,347 $ 41,768 1,428 722 1,127 1,787 92 646 2,083 49,653 1,282 603 1,885 45,462 (45,462) $ - - 758 758 48,895 (48,895) $ - As of September 26, 2009, the Partnership’s Corporate Entities had tax loss carryforwards for federal income tax reporting purposes of approximately $96,025, which are available to offset future federal taxable income and expire between 2024 and 2028. 8. Long-Term Borrowings Short-term and long-term borrowings consist of the following: Senior Notes, 6.875%, due December 15, 2013, net of unamortized discount of $585 and $1,228, respectively Revolving Credit Agreement, due June 25, 2013 Term Loan Less: current portion of Term Loan As of September 26, 2009 September 27, 2008 $ $ 249,415 100,000 - 349,415 - 349,415 423,772 - 110,000 533,772 2,000 531,772 $ $ The Partnership and its subsidiary, Suburban Energy Finance Corporation, have issued $425,000 aggregate principal amount of Senior Notes (the “2003 Senior Notes) with an annual interest rate of 6.875%. On September 9, 2009, the Partnership and its subsidiary purchased $175,000 aggregate principal amount of the 2003 Senior Notes through a cash tender offer. In connection with the tender offer, the Partnership recognized a loss on the extinguishment of debt of $4,624 in the fourth quarter of fiscal 2009, consisting of $2,821 for the tender premium and related fees, as well as the write-off of $1,803 in unamortized debt origination costs and unamortized discount. F-18 The Partnership’s obligations under the 2003 Senior Notes are unsecured and rank senior in right of payment to any future subordinated indebtedness and equally in right of payment with any future senior indebtedness. The 2003 Senior Notes are structurally subordinated to, which means they rank effectively behind, any debt and other liabilities of the Operating Partnership. The Senior Notes mature on December 15, 2013 and require semi-annual interest payments in June and December. The Partnership is permitted to redeem some or all of the 2003 Senior Notes any time at redemption prices specified in the indenture governing the 2003 Senior Notes. In addition, in the event of a change of control of the Partnership, as defined in the indenture governing the 2003 Senior Notes, the Partnership must offer to repurchase the notes at 101% of the principal amount repurchased, if the holders of the notes exercise the right of repurchase. 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 replaces 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 $57,166 primarily in support of retention levels under its self-insurance programs, which expire periodically through April 15, 2010. Therefore, as of September 26, 2009 the Partnership had available borrowing capacity of $92,834 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 ½ 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 26, 2009, the interest rate for the Revolving Credit Facility was approximately 4.1%. 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. In connection with the Revolving Credit Facility, the Operating Partnership amended its existing interest rate swap agreement, which has a termination date of March 31, 2010, to reduce the notional amount to $100,000 from $108,000. The Operating Partnership will pay a fixed interest rate of 4.66% to the issuing lender on the notional principal amount outstanding, effectively fixing the LIBOR portion of the interest rate at 4.66%. In return, the issuing lender will pay to the Operating Partnership a floating rate, namely LIBOR, on the same notional principal amount. On July 31, 2009 our Operating Partnership entered into a forward starting interest rate swap agreement with a March 31, 2010 effective date, which is commensurate with the maturity of the existing interest rate swap agreement, and termination date of June 25, 2013. Under the forward starting 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. The interest rate swaps have been designated as a cash flow hedge. F-19 The Revolving Credit Facility and the 2003 Senior Notes both contain various restrictive and affirmative covenants applicable to the Operating Partnership and the Partnership, respectively, including (i) restrictions on the incurrence of additional indebtedness, and (ii) restrictions on certain liens, investments, guarantees, loans, advances, payments, mergers, consolidations, distributions, sales of assets and other transactions. The Revolving Credit Facility contains certain financial covenants (a) requiring the consolidated interest coverage ratio, as defined, of the Partnership 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 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 2003 Senior Note indenture, the Partnership is generally permitted to make cash distributions equal to available cash, as defined, as of the end of the immediately preceding quarter, if no event of default exists or would exist upon making such distributions, and the Partnership’s consolidated fixed charge coverage ratio, as defined, is greater than 1.75 to 1. The Partnership and the Operating Partnership were in compliance with all covenants and terms of the 2003 Senior Notes and the Revolving Credit Facility as of September 26, 2009. 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 26, 2009 and September 27, 2008 include debt origination costs with a net carrying amount of $7,136 and $4,902, respectively. Aggregate amortization expense related to deferred debt origination costs included within interest expense for the years ended September 26, 2009, September 27, 2008 and September 29, 2007 was $1,923, $1,328 and $1,327, respectively. Unamortized debt origination costs of $414 associated with the previous credit facility were written-off in the third quarter of fiscal 2009 and unamortized debt origination costs of $1,385 associated with the tender offer of the 2003 Senior Notes were written-off in the fourth quarter of fiscal 2009. The aggregate amounts of long-term debt maturities in fiscal years subsequent to September 26, 2009 are as follows: 2010 through 2012 - $-0-; 2013 - $100,000; 2014 - $250,000; and thereafter - $-0-. Under the previous credit facility, proceeds from the sale, transfer or other disposition of any asset of the Operating Partnership, other than the sale of inventory in the ordinary course of business, in excess of $15,000 was required to be used to acquire productive assets within twelve months of receipt of the proceeds. Any proceeds not used within twelve months of receipt to acquire productive assets were required to be used to prepay the outstanding principal of the Term Loan. On September 26, 2008 and November 10, 2008, the Operating Partnership prepaid $15,000 and $2,000, respectively, on the Term Loan with the net proceeds from the sale of the Tirzah storage facility that were not used to acquire productive assets within twelve months of receipt. 9. 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. The Partnership has historically recognized unearned compensation associated with awards under its Restricted Unit Plans ratably to expense over the vesting period based on the fair value of the award on the grant date and has historically recognized compensation cost and the associated unearned compensation liability for equity-based awards under its Long-Term Incentive Plan. 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 F-20 members of the Board of Supervisors of the Partnership. The total number of Common Units authorized for issuance under the Restricted Unit Plans is 1,917,805. Unless otherwise stipulated by the compensation committee 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 or vote their respective restricted units until vested. Because each restricted unit represents a promise to issue a Common Unit at a future date, 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. The following is a summary of activity in the Restricted Unit Plans: Outstanding September 30, 2006 Granted Forfeited Vested Outstanding September 29, 2007 Granted Forfeited Vested Outstanding September 27, 2008 Granted Forfeited Vested Outstanding September 26, 2009 Weighted Average Grant Date Fair Value Per Unit $29.28 44.51 (30.06) (28.34) $28.85 35.19 (27.17) (30.52) $30.57 18.10 (31.92) (27.81) $28.89 Units 340,786 151,515 (47,023) (62,188) 383,090 125,912 (11,359) (51,128) 446,515 68,799 (28,382) (71,637) 415,295 As of September 26, 2009, unrecognized compensation cost related to unvested restricted units awarded under the Restricted Unit Plans amounted to $4,549. Compensation cost associated with the unvested awards is expected to be recognized over a weighted-average period of 1.7 years. Compensation expense for the Restricted Unit Plans for years ended September 26, 2009, September 27, 2008 and September 29, 2007 was $2,396, $2,156 and $3,014, respectively. Long-Term Incentive Plan. The Partnership has a non-qualified, unfunded long-term incentive plan for officers and key employees (“LTIP-2”) which provides for payment, in the form of cash, for an award of equity-based compensation at the end of a three-year performance period. The level of compensation earned under LTIP-2 is based on the market performance of the Partnership’s Common Units on the basis of total return to Unitholders (“TRU”) compared to the TRU of a predetermined peer group comprised of other publicly traded partnerships (master limited partnerships), as approved by the Compensation Committee of the Board of Supervisors, over the same three-year performance period. Compensation expense, which includes adjustments to previously recognized compensation expense for current period changes in the fair value of unvested awards, for the years ended September 26, 2009, September 27, 2008 and September 29, 2007 was $3,402, $1,859 and $5,977, respectively. The cash payouts in fiscal 2009, fiscal 2008 and fiscal 2007, which related to the fiscal 2006, fiscal 2005 and fiscal 2004 awards, were $2,741, $2,720 and $1,215, respectively. F-21 10. Compensation Deferral Plan The Compensation Deferral Plan provided eligible employees of the Partnership the ability to defer receipt of all or a portion of vested restricted units granted under a prior restricted unit award plan. These units were held in trust on behalf of the individuals. During the second quarter of fiscal 2008, the remaining 292,682 Common Units were distributed to the participants resulting in the satisfaction of the deferred compensation obligation of $5,660, classified in partners’ capital and a corresponding reduction to common units held in trust, classified as a contra-equity balance within partners’ capital. 11. Employee Benefit Plans Defined Contribution Plan. The Partnership has an employee Retirement Savings and Investment Plan (the “401(k) Plan”) covering most employees. Employer matching contributions relating to the 401(k) Plan are a percentage of the participating employees’ elective contributions. The percentage of the Partnership’s contributions are based on a sliding scale depending on the Partnership’s achievement of annual performance targets. These contributions totaled $5,676, $1,190 and $5,426 for the years ended September 26, 2009, September 27, 2008 and September 29, 2007, respectively. Defined Pension and Retiree Health and Life Benefits Arrangements Pension Benefits. The Partnership has a noncontribut ory defined benefit pension plan which was originally designed to cover all eligible employees of the Partnership who met certain requirements as to age and length of service. Effective January 1, 1998, the Partnership amended its defined benefit pension plan to provide benefits under a cash balance formula as compared to a final average pay formula which was in effect prior to January 1, 1998. Effective January 1, 2000, participation in the defined benefit pension plan was limited to eligible existing participants on that date with no new participants eligible to participate in the plan. On September 20, 2002, the Board of Supervisors approved an amendment to the defined benefit pension plan whereby, effective January 1, 2003, future service credits ceased and eligible employees receive interest credits only toward their ultimate retirement benefit. Contributions, as needed, are made to a trust maintained by the Partnership. Contributions to the defined benefit pension plan are made by the Partnership in accordance with the Employee Retirement Income Security Act of 1974 minimum funding standards plus additional amounts made at the discretion of the Partnership, which may be determined from time to time. There were no minimum funding requirements for the defined benefit pension plan for fiscal 2009, 2008 or 2007. In recent years, cash balance defined benefit pension plans have come under increased scrutiny resulting in litigation regarding such plans sponsored by other companies. Partly in response to these developments, the federal Pension Protection Act of 2006 (the “2006 Pension Act”) was enacted, and these developments may result in further legislative changes impacting cash balance defined benefit pension plans in the future. There can be no assurances that future legislative developments will not have an adverse effect on the Partnership’s results of operations or cash flows. Retiree Health and Life Benefits. The Partnership provides postretirement health care and life insurance benefits for certain retired employees. Partnership employees hired prior to July 1993 are eligible for postretirement life insurance benefits if they reach a specified retirement age while working for the Partnership. Partnership employees hired prior to July 1993 and who retired prior to March 1998 are eligible for postretirement health care benefits if they reached a specified retirement age while working for the Partnership. Effective January 1, 2000, the Partnership terminated its postretirement health care benefit plan for all eligible employees retiring after March 1, 1998. All active employees who were eligible to receive health care benefits under the postretirement plan subsequent to March 1, 1998, were provided an increase to their accumulated benefits under the cash balance pension plan. The Partnership’s postretirement health care and life insurance benefit plans are unfunded. Effective January 1, 2006, the Partnership changed its postretirement health care plan from a self-insured program to one that is fully insured under which the Partnership pays a portion of the insurance premium on behalf of the eligible F-22 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. At the end of fiscal 2007, the Partnership adopted a new accounting standard pertaining to employers’ accounting for defined benefit pension and other postretirement benefit plans. The initial impact of adopting this standard was to recognize in accumulated other comprehensive income (loss) unrecognized prior service costs or credits and net actuarial gains or losses that were previously unrecognized. The following table summarizes the effect of required changes in the additional minimum liability (“AML”) reported in accumulated other comprehensive loss as of September 29, 2007 prior to the adoption of the new standard, as well as the initial impact of adoption. The AML was eliminated during fiscal 2007, primarily as a result of employer contributions. September 29, 2007 Prior to AML adjustments and adoption of new accounting standard AML adjustments prior to adoption of new accounting standard Adoption of new accounting standard September 29, 2007 Post AML adjustments and adoption of new accounting standard Accrued pension liability (asset) Accrued postretirement liability Accumulated other comprehensive loss $ 9,990 $ (63,510) $ 47,973 $ (5,547) $ 29,353 $ - $ (4,928) $ 24,425 $ 63,510 $ (63,510) $ 43,045 $ 43,045 Projected Benefit Obligation, Fair Value of Plan Assets and Funded Status. The following tables provide a reconciliation of the changes in the benefit obligations and the fair value of the plan assets for each of the years ended September 26, 2009 and September 27, 2008 and a statement of the funded status for both years. Under the Partnership’s defined benefit pension plan, the accumulated benefit obligation and the projected benefit obligation are the same. F-23 Reconciliation of benefit obligations: Benefit obligation at beginning of year Service cost Interest cost Actuarial (gain) loss Settlement payments Benefits paid Benefit obligation at end of year Reconciliation of fair value of plan assets: Fair value of plan assets at beginning of year Actual return on plan assets Employer contributions Settlement payments Benefits paid Fair value of plan assets at end of year Funded status: Funded status at end of year Amounts recognized in consolidated balance sheets consist of: Pension (liability) asset Accrued benefit liability Net amount recognized at end of year Less: Current portion Non-current benefit liability Pension Benefits 2009 2008 Retiree Health and Life Benefits 2009 2008 $ $ $ $ 135,195 - 9,488 26,888 (6,130) (8,254) 157,187 135,327 19,112 - (6,130) (8,254) 140,055 $ $ 158,317 - 8,749 (16,904) (6,653) (8,314) 135,195 163,864 (13,570) - (6,653) (8,314) 135,327 $ $ $ $ 19,076 5 1,381 2,409 - (1,744) 21,127 24,426 8 1,399 (4,954) - (1,803) 19,076 $ $ - $ - 1,744 - (1,744) $ - - $ - 1,803 - (1,803) - $ $ (17,132) $ 132 $ (21,127) $ (19,076) $ $ $ (17,132) - (17,132) - (17,132) $ $ $ 132 - 132 - 132 $ - (21,127) (21,127) 1,748 (19,379) $ $ $ - (19,076) (19,076) 1,923 (17,153) $ $ Amounts not yet recognized in net periodic benefit cost and included in accumulated other comprehensive income (loss): Actuarial net (loss) gain Prior service credits Net amount recognized in accumulated other comprehensive (loss) income $ (63,278) - $ (50,345) - $ 2,842 3,338 $ 5,563 3,826 $ (63,278) $ (50,345) $ 6,180 $ 9,389 The amounts in accumulated other comprehensive loss as of September 26, 2009 that are expected to be recognized as components of net periodic benefit costs during the next fiscal year are $5,374 and ($555) for pension and postretirement benefits, respectively. Plan Asset Allocation. The following table presents the actual allocation of assets held in trust as of September 26, 2009 and September 27, 2008: Fixed income securities - long-term bonds Equity securities - domestic and international 2009 92% 8% 92% 2008 81% 19% 100% The Partnership’s investment policies and strategies, as set forth in the Investment Management Policy and Guidelines, are monitored by a Benefits Committee comprised of five members of management. During fiscal 2007, the Benefits Committee proposed and the Board of Supervisors approved contributions to the plan in order to F-24 improve the funded status of the accumulated benefit obligation and to change the plan’s asset allocation to reduce investment risk and more closely match the asset mix to the future cash requirements of the plan. The implementation of this strategy resulted in a $25,000 voluntary contribution in fiscal 2007, and a change in the asset allocation to reflect a greater concentration of fixed income securities. The fixed income portion is invested in a combination of long-term U.S. government bonds and intermediate-term corporate bonds with a strategy to match the actuarially estimated duration of the plan’s projected benefit obligations. The target asset mix is as follows: (i) fixed income securities portion of the portfolio should range between 75% and 95%; and (ii) equity securities portion of the portfolio should range between 5% and 25%. Projected Contributions and Benefit Payments. There are no projected minimum funding requirements under the Partnership’s defined benefit pension plan for fiscal 2010. Estimated future benefit payments for both pension and retiree health and life benefits are as follows: Fiscal Year 2010 2011 2112 2013 2014 2015 through 2019 Pension Benefits $ 19,896 13,380 13,810 12,720 12,986 54,113 Retiree Health and Life Benefits $ 1,748 1,690 1,635 1,562 1,489 6,137 Effect on Operations. The following table provides the components of net periodic benefit costs included in operating expenses for the years ended September 26, 2009, September 27, 2008 and September 29, 2007: Pension Benefits 2008 2007 2009 Retiree Health and Life Benefits 2009 2007 2008 Service cost Interest cost Expected return on plan assets Amortization of prior service credit Settlement charge Recognized net actuarial loss Net periodic benefit costs $ - 9,487 (9,205) - - 4,050 4,332 $ $ - 8,749 (9,082) - - 3,375 3,042 $ - $ 8,905 (10,317) - 3,269 5,315 7,172 $ 4 $ 1,381 - (490) - (312) 583 $ 8 $ 1,399 - (490) - - 917 $ $ 12 1,317 - (597) - - 732 $ During fiscal 2007, lump sum pension benefit payments to either terminated or retiring individuals amounted to $10,786, which exceeded the settlement threshold (combined service and interest costs of net periodic pension cost) of $8,905 for fiscal 2007, and as a result, the Partnership was required to recognize a non-cash settlement charge of $3,269 during the fourth quarter of fiscal 2007. The non-cash charge was required to accelerate recognition of a portion of cumulative unrecognized losses in the defined benefit pension plan. During fiscal 2009 and 2008, 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. F-25 Actuarial Assumptions. The assumptions used in the measurement of the Partnership’s benefit obligations as of September 26, 2009 and September 27, 2008 are shown in the following table: Pension Benefits 2009 2008 Retiree Health and Life Benefits 2009 2008 Weighted-average discount rate Average rate of compensation increase 5.125% n/a 7.625% n/a 5.125% n/a 7.625% n/a The assumptions used in the measurement of net periodic pension benefit and postretirement benefit costs for the years ended September 26, 2009, September 27, 2008 and September 29, 2007 are shown in the following table: Pension Benefits 2008 2007 2009 Retiree Health and Life Benefits 2009 2007 2008 Weighted-average discount rate Average rate of compensation increase Weighted-average expected long- term rate of return on plan assets Health care cost trend 7.625% 6.000% 5.500% 7.625% 6.000% 5.500% n/a n/a n/a n/a n/a n/a 7.390% n/a 6.000% n/a 8.000% n/a n/a 9.000% n/a 9.500% n/a 10.000% 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. The 9.00% increase in health care costs assumed at September 26, 2009 is assumed to decrease gradually to 5.00% in fiscal 2017 and to remain at that level thereafter. Increasing the assumed health care cost trend rates by 1.0% in each year would increase the Partnership’s benefit obligation as of September 26, 2009 by approximately $432 and the aggregate of service and interest components of net periodic postretirement benefit expense for the year ended September 26, 2009 by approximately $28. Decreasing the assumed health care cost trend rates by 1.0% in each year would decrease the Partnership’s benefit obligation as of September 26, 2009 by approximately $390 and the aggregate of service and interest components of net periodic postretirement benefit expense for the year ended September 26, 2009 by approximately $26. The Partnership has concluded that the prescription drug benefits within the retiree medical plan do not entitle the Partnership to an available Medicare subsidy. F-26 12. Financial Instruments 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 notional amount of the Partnership’s outstanding derivative instruments includes the following (gallons in thousands): Transaction Type Commodity Options Commodity Futures As of September 26, 2009 September 27, 2008 6,467 15,330 6,246 - The following summarizes the gross fair value of the Partnership’s derivative instruments and their location in the consolidated balance sheet as of September 26, 2009 and September 27, 2008, respectively: Asset Derivatives Derivatives not designated as hedging instruments: Commodity options As of September 26, 2009 Location Fair Value As of September 27, 2008 Location Fair Value Other current assets Other assets $ 6,398 241 Other current assets Other assets $ 5,048 - Commodity futures Other current assets Other assets 2,845 248 9,732 $ Other current assets Other assets - - 5,048 $ Liability Derivatives Derivatives designated as hedging instruments: Interest rate swaps Derivatives not designated as hedging instruments: Commodity options Location Fair Value Location Fair Value Other current liabilities Other liabilities $ $ 3,351 840 4,191 Other current liabilities Other liabilities $ $ 2,441 759 3,200 Other current liabilities Other liabilities $ 4,060 175 Other current liabilities Other liabilities 494 $ - Commodity futures Other current liabilities 784 5,019 $ Other current liabilities - $ 494 As of September 26, 2009, the Partnership’s outstanding commodity-related derivatives mature between fiscal 2010 and fiscal 2011, and have a weighted average maturity of approximately 7 months. As of September 27, 2008, the Partnership’s outstanding commodity-related derivatives mature between fiscal 2009 and fiscal 2010, and have a weighted average maturity of approximately 6 months. F-27 The effect of the Partnership’s derivative instruments on the consolidated statement of operations for the years ended September 27, 2009, September 27, 2008 and September 29, 2007 are as follows: Derivatives in Cash Flow Hedging Relationships: Year ended 9/26/2009 Interest rate swap Amount of Gains (Losses) Recognized in OCI (Effective Portion) Gains (Losses) Reclassified from Accumulated OCI into Income (Effective Portion) Location Amount $ (991) Interest expense $ - Year ended 9/27/2008 Interest rate swap Forwards Year ended 9/29/2007 Interest rate swap Forwards Futures $ $ (2,916) - (2,916) $ $ (1,465) 1,292 - (173) Interest expense Cost of products sold Interest expense Cost of products sold Cost of products sold - $ 1,377 1,377 $ - $ (2,961) 994 (1,967) $ Derivatives Not Designated as Hedging Instruments: Year ended 9/26/2009 Options Futures Year ended 9/27/2008 Options Futures Year ended 9/29/2007 Options Futures Location of Gains (Losses) Recognized in Income Amount of Unrealized Gains (Losses) Recognized in Income Cost of products sold Cost of products sold $ (589) 2,302 $ 1,713 Cost of products sold Cost of products sold $ 2,011 (247) $ 1,764 Cost of products sold Cost of products sold $ (2,599) (4,956) $ (7,555) Credit Risk. The Partnership’s principal customers are resi dential 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 2009, 2008 or 2007 and no concentration of receivables exists as of September 26, 2009 or September 27, 2008. During fiscal 2009, 2008 and 2007, three suppliers provided approximately 40%, 35% and 34%, 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 forward and option contracts entered into with various third parties to the extent the counterparties do not perform. The Partnership evaluates the financial condition of each counterparty with which it conducts business and establishes credit limits to reduce exposure to credit risk based on non-performance. The Partnership does not require collateral to support the contracts. F-28 Bank Debt and Senior Notes. The fair value of the Revolving Credit Facility approximates the carrying value since the interest rates are periodically adjusted to reflect market conditions. Based upon quoted market prices, the fair value of the Partnership’s 6.875% Senior Notes was $248,125 as of September 26, 2009. 13. Commitments and Contingencies Commitments. The Partnership leases certain property, plant and equipment, including portions of the Partnership’s vehicle fleet, for various periods under noncancelable leases. Rental expense under operating leases was $17,254, $17,739 and $19,611 for the years ended September 26, 2009, September 27, 2008 and September 29, 2007, respectively. Future minimum rental commitments under noncancelable operating lease agreements as of September 26, 2009 are as follows: Fiscal Year 2010 2011 2012 2013 2014 2015 and thereafter Contingencies. Minimum Lease Payments $ 14,297 11,461 8,643 6,791 5,522 4,223 Self Insurance. As discussed in Note 2, the Partnership is self-insured for general and product, workers’ compensation and automobile liabilities up to predetermined amounts above which third party insurance applies. At September 26, 2009 and September 27, 2008, the Partnership had accrued liabilities of $52,248 and $73,033, respectively, representing the total estimated losses under these self-insurance programs. The Partnership is also involved in various legal actions which have arisen in the normal course of business, including those relating to commercial transactions and product liability. Management believes, based on the advice of legal counsel, that the ultimate resolution of these matters will not have a material adverse effect on the Partnership’s financial position or future results of operations, after considering its self-insurance liability for known and unasserted self-insurance claims, as well as existing insurance policies in force. 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 $14,812 and $38,825 as of September 26, 2009 and September 27, 2008, respectively. During the first quarter of fiscal 2009, the Partnership agreed to settle a litigation involving alleged product liability for approximately $30,000. The settlement was covered by insurance above the level of the Partnership’s deductible. As a result of this settlement, in which the Partnership denied any liability, the Partnership increased the portion of its estimated self-insurance liability that exceeded the insurance deductible and established a corresponding asset of $30,000 as of September 27, 2008 to accrue for the settlement and subsequent reimbursement from the Partnership’s third party insurance carrier. During fiscal 2009, the Partnership fully paid the $30,000 to the claimants in this matter and was reimbursed for the same amount from the Partnership’s third party insurance carrier. Legal Matters. Following the Operating Partnership’s 1999 acquisition of the propane assets of SCANA Corporation (“SCANA”), Heritage Propane Partners, L.P. had brought an action against SCANA for breach of contract and fraud and against the Operating Partnership for tortious interference with contract and tortious interference with prospective contract. On October 21, 2004, the jury returned a unanimous verdict in favor of the Operating Partnership on all claims, but against SCANA. After the jury returned the verdict against SCANA, F-29 the Operating Partnership filed a cross-claim against SCANA for indemnification, seeking to recover defense costs. On November 2, 2006, SCANA and the Operating Partnership reached a settlement agreement wherein the Operating Partnership received $2,000 as a reimbursement of defense costs incurred as a result of the lawsuit. The $2,000 was recorded as a reduction to general and administrative expenses during the first quarter of fiscal 2007. 14. Guarantees The Partnership has residual value guarantees associated with certain of its operating leases, related primarily to transportation equipment, with remaining lease periods scheduled to expire periodically through fiscal 2016. 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 $18,337. The fair value of residual value guarantees for outstanding operating leases was de minimis as of September 26, 2009 and September 27, 2008. 15. 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. These transactions increased the total number of Common Units outstanding by 2,430,934 to 35,227,954. 16. Discontinued Operations and Disposition The Partnership continuously evaluates its existing operations to identify opportunities to optimize the return on assets employed and selectively divests operations in slower growing or non-strategic markets and seeks to reinvest in markets that are considered to present more opportunities for growth. In line with that strategy, on October 2, 2007, the Operating Partnership completed the sale of its Tirzah, South Carolina underground granite propane storage cavern, and associated 62-mile pipeline, for $53,715 in cash, after taking into account certain adjustments. The 57.5 million gallon underground storage cavern is connected to the Dixie Pipeline and provides propane storage for the eastern United States. As part of the agreement, the Operating Partnership entered into a long-term storage arrangement, not to exceed 7 million propane gallons, with the purchaser of the cavern that will enable the Operating Partnership to continue to meet the needs of its retail operations, consistent with past practices. As a result of this sale, a gain of $43,707 was reported as a gain from the disposal of discontinued operations in the Partnership’s results for the first quarter of fiscal 2008. The results of operations from the Tirzah facilities in the comparative prior year periods have been reclassified to discontinued operations on the consolidated statements of operations for the fiscal year ended September 29, 2007. During the first quarter of fiscal 2007, in a non-cash transaction, the Partnership completed a transaction in which it disposed of nine customer service centers considered to be non-strategic in exchange for three customer service centers of another company located in Alaska. The Partnership reported a $1,002 gain within discontinued operations in the first quarter of fiscal 2007 for the amount by which the fair value of assets relinquished exceeded the carrying value of the assets relinquished. During the second half of fiscal 2007, the Partnership sold three customer service centers for net cash proceeds of $1,284 and reported a gain of $885 on disposal of discontinued operations. Prior period results of operations attributable to these customer service centers were not significant and, as such, have not been reclassified as discontinued operations. F-30 17. 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 the same as those described in the summary of significant accounting policies in Note 2. The propane segment is primarily engaged in the retail distribution of propane to residential, commercial, industrial and agricultural customers and, to a lesser extent, wholesale distribution to large industrial end users. In the residential and commercial markets, propane is used primarily for space heating, water heating, cooking and clothes drying. Industrial customers use propane generally as a motor fuel burned in internal combustion engines that power over-the-road vehicles, forklifts and stationary engines, to fire furnaces and as a cutting gas. In the agricultural markets, propane is primarily used for tobacco curing, crop drying, poultry brooding and weed control. The fuel oil and refined fuels segment is primarily engaged in the retail distribution of fuel oil, diesel, kerosene and gasoline to residential and commercial customers for use primarily as a source of heat in homes and buildings. The natural gas and electricity segment is engaged in the marketing of natural gas and electricity to residential and commercial customers in the deregulated energy markets of New York and Pennsylvania. Under this operating segment, the Partnership owns the relationship with the end consumer and has agreements with the local distribution companies to deliver the natural gas or electricity from the Partnership’s suppliers to the customer. Activities in the all other category include the Partnership’s services business, which is primarily engaged in the sale, installation and servicing of a wide variety of home comfort equipment, particularly in the areas of heating and ventilation and activities from the Partnership’s HomeTown Hearth & Grill and Suburban Franchising subsidiaries. F-31 The following table presents certain data by reportable segment and provides a reconciliation of total operating segment information to the corresponding consolidated amounts for the periods presented: September 26, 2009 Year Ended September 27, 2008 September 29, 2007 Revenues: Propane Fuel oil and refined fuels Natural gas and electricity All other Total revenues Income (loss) before interest expense and provision for income taxes: Propane Fuel oil and refined fuels Natural gas and electricity All other Corporate Total income before interest expense and provision for income taxes Reconciliation to income from continuing operations Loss on debt extinguishment Interest expense, net Provision for income taxes Depreciation and amortization: Propane Fuel oil and refined fuels Natural gas and electricity All other Corporate Income from continuing operations $ Assets: Propane Fuel oil and refined fuels Natural gas and electricity All other Corporate Eliminations Total assets $ $ $ 864,012 159,596 76,832 42,714 1,143,154 1,132,950 288,078 103,745 49,390 1,574,163 $ $ $ 1,019,798 262,076 94,352 63,337 1,439,563 $ 268,969 17,950 12,791 (16,346) (72,749) $ 219,546 (2,825) 9,812 (16,044) (60,361) $ 207,269 26,283 11,404 (26,335) (54,025) 210,615 150,128 164,596 4,624 38,267 2,486 165,238 - 37,052 1,903 111,173 $ - 35,596 5,653 123,347 $ $ $ $ 15,515 3,381 1,008 391 8,099 28,394 16,229 3,493 929 721 7,418 28,790 15,951 4,253 1,008 436 8,695 30,343 681,809 83,416 17,540 2,876 279,854 (87,981) 977,514 F-32 As of September 26, 2009 September 27, 2008 $ $ 746,281 70,548 23,658 4,075 279,132 (87,981) 1,035,713 $ $ Total depreciation and amortization $ $ $ INDEX TO FINANCIAL STATEMENT SCHEDULE SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES Schedule II Valuation and Qualifying Accounts – Years Ended September 26, 2009, September 27, 2008 and September 29, 2007........................................................................... S-2 Page S-1 SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES VALUATION AND QUALIFYING ACCOUNTS (in thousands) SCHEDULE II Balance at Beginning of Period Charged (credited) to Costs and Expenses Other Additions Deductions (a) Balance at End of Period Year Ended September 29, 2007 Allowance for doubtful accounts Valuation allowance for deferred tax assets $ 5,530 47,733 $ 4,331 (1,583) $ - - $ (4,820) (2,854) $ 5,041 43,296 Year Ended September 27, 2008 Allowance for doubtful accounts Valuation allowance for deferred tax assets $ 5,041 43,296 $ 9,166 6,930 $ - - $ (7,629) (1,331) $ 6,578 48,895 Year Ended September 26, 2009 Allowance for doubtful accounts Valuation allowance for deferred tax assets $ 6,578 48,895 $ 3,284 (2,048) - $ - $ (5,488) (1,385) $ 4,374 45,462 (a) Represents amounts that did not impact earnings. S-2 EXHIBIT 21.1 SUBSIDIARIES OF SUBURBAN PROPANE PARTNERS, L.P. (as of November 25, 2009) SUBURBAN LP HOLDING, INC. (Delaware) SUBURBAN LP HOLDING, LLC (Delaware) SUBURBAN PROPANE, L. P. (Delaware) SUBURBAN SALES & SERVICE, INC. (Delaware) GAS CONNECTION, LLC (Oregon) (d/b/a HomeTown Hearth & Grill) SUBURBAN FRANCHISING, LLC (Nevada) SUBURBAN ENERGY FINANCE CORP. (Delaware) SUBURBAN PLUMBING NEW JERSEY, LLC (Delaware) SUBURBAN HEATING OIL PARTNERS, LLC (Delaware) (d/b/a Suburban Propane) AGWAY ENERGY SERVICES, LLC (Delaware) SUBURBAN ALBANY PROPERTY, LLC (Delaware) SUBURBAN BUTLER MONROE STREET PROPERTY, LLC (Delaware) SUBURBAN CANTON ROUTE 11 PROPERTY, LLC (Delaware) SUBURBAN CHAMBERSBURG FIFTH AVENUE PROPERTY, LLC (Delaware) SUBURBAN ELLENBURG DEPOT PROPERTY, LLC (Delaware) SUBURBAN GETTYSBURG PROPERTY, LLC (Delaware) SUBURBAN LEWISTOWN PROPERTY, LLC (Delaware) SUBURBAN MA SURPLUS PROPERTY, LLC (Delaware) SUBURBAN MARCY PROPERTY, LLC (Delaware) SUBURBAN MIDDLETOWN NORTH STREET PROPERTY, LLC (Delaware) SUBURBAN NEW MILFORD SMITH STREET PROPERTY, LLC (Delaware) SUBURBAN NJ PROPERTY ACQUISITIONS, LLC (Delaware) SUBURBAN NJ SURPLUS PROPERTY, LLC (Delaware) SUBURBAN NY PROPERTY ACQUISITIONS, LLC (Delaware) SUBURBAN NY SURPLUS PROPERTY, LLC (Delaware) SUBURBAN PA PROPERTY ACQUISITIONS, LLC (Delaware) SUBURBAN PA SURPLUS PROPERTY, LLC (Delaware) SUBURBAN ROCHESTER PROPERTY, LLC (Delaware) SUBURBAN SODUS PROPERTY, LLC (Delaware) SUBURBAN TEMPLE PROPERTY, LLC (Delaware) SUBURBAN TOWANDA PROPERTY, LLC (Delaware) SUBURBAN VERBANK PROPERTY, LLC (Delaware) SUBURBAN VINELAND PROPERTY, LLC (Delaware) SUBURBAN VT PROPERTY ACQUISITIONS, LLC (Delaware) SUBURBAN WALTON PROPERTY, LLC (Delaware) SUBURBAN WASHINGTON PROPERTY, LLC (Delaware) EXHIBIT 23.1 CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (No. 333- 109714) and Form S-8 (Nos. 333-72972, 333-138093 and 333-160768) of Suburban Propane Partners, L.P. of our report dated November 25, 2009 relating to the financial statements, financial statement schedule, and the effectiveness of internal control over financial reporting, which appears in this Form 10-K. PricewaterhouseCoopers LLP Florham Park, New Jersey November 25, 2009  Certification of the President and Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 EXHIBIT 31.1 I, Michael J. Dunn, Jr., certify that: 1. I have reviewed this Annual Report on Form 10-K of Suburban Propane Partners, L.P.; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and 5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s Board of Supervisors: a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. November 25, 2009 By: /s/ MICHAEL J. DUNN, JR. Michael J. Dunn, Jr. President and Chief Executive Officer Certification of the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 EXHIBIT 31.2 I, Michael A. Stivala, certify that: 1. I have reviewed this Annual Report on Form 10-K of Suburban Propane Partners, L.P.; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and 5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s Board of Supervisors: a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. November 25, 2009 By: /s/ MICHAEL A. STIVALA Michael A. Stivala Chief Financial Officer 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 EXHIBIT 32.1 In connection with the Annual Report of Suburban Propane Partners, L.P. (the “Partnership”) on Form 10-K for the period ended September 26, 2009 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Michael J. Dunn, Jr., President and Chief Executive Officer of the Partnership, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge: (1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership. By: /s/ MICHAEL J. DUNN, JR. Michael J. Dunn, Jr. President and Chief Executive Officer November 25, 2009 This certification shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), or incorporated by reference in any filing under the Securities Act of 1933, as amended, or the Exchange Act, except as shall be expressly set forth by specific reference in such a filing. 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 EXHIBIT 32.2 In connection with the Annual Report of Suburban Propane Partners, L.P. (the “Partnership”) on Form 10-K for the period ended September 26, 2009 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Michael A. Stivala, Chief Financial Officer of the Partnership, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge: (1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership. By: /s/ MICHAEL A. STIVALA Michael A. Stivala Chief Financial Officer November 25, 2009 This certification shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), or incorporated by reference in any filing under the Securities Act of 1933, as amended, or the Exchange Act, except as shall be expressly set forth by specific reference in such a filing. FIVE-YEAR PERFORMANCE GRAPH 1 EXHIBTI 99.1 The following graph compares the performance of our Common Units with the performance of the New York Stock Exchange Index (the “NYSE Market Index”) and a peer group index for the period of the five fiscal years commencing September 25, 2004. The graph assumes that at the beginning of the period, $100 was invested in each of (1) our Common Units, (2) the NYSE Index, and (3) the peer group, and that all distributions or dividends were reinvested. We do not believe than any published industry or line-of-business index accurately reflects our business. Accordingly, we have created a special peer group index consisting of three other propane-marketing companies whose common units are publicly traded on the NYSE. Our peer group index includes the common units of the following companies: Ferrellgas Partners, L.P., AmeriGas Partners, L.P., and Inergy, L.P. COMPARISON OF 5-YEAR CUMULATIVE TOTAL RETURN AMONG SUBURBAN PROPANE PARTNERS, L.P., NYSE MARKET INDEX AND PEER GROUP INDEX 200 175 150 125 100 75 50 25 S R A L L O D 0 2004 2005 2006 2007 2008 2009 SUBURBAN PROPANE PARTNERS, L.P. PEER GROUP INDEX NYSE MARKET INDEX ASSUMES $100 INVESTED ON SEPT. 25, 2004 ASSUMES DIVIDEND REINVESTED FISCAL YEAR ENDING SEPT. 25, 2009 1 The performance graph shall not be deemed incorporated by reference by any general statement incorporating by reference this Annual Report on Form 10-K into any filing under the Securities Act of 1933, as amended or the Securities Exchange Act of 1934, as amended, except to the extent that Suburban specifically incorporates this information by reference in such filing, and shall not otherwise be deemed filed under such Acts. Suburban Propane Partners, L.P. One Suburban Plaza (cid:129) 240 Route 10 West P.O. Box 206 Whippany, New Jersey 07981-0206 www.suburbanpropane.com 

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