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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. 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):

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 ~~24, 2012~~30, 2013 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 ($~~42.29~~44.50 per unit), was approximately ~~$1,501,329,000.~~$2,541,902,000.

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:

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.

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 onLP/Gas Magazine dated February ~~2012,~~2013, and after considering the effect of, among other transactions in the propane industry, the Inergy Propane Acquisition (as defined below), that we are the third largest retail marketer of propane in the United States, measured by retail gallons sold in the calendar year ~~2011.~~2012. As of September ~~29, 2012,~~28, 2013, we were serving the energy needs of more than 1.2 million residential, commercial, industrial and agricultural customers through approximately 750 locations in 41 states. Our operations are concentrated in the east and west coast regions of the United States, including Alaska and, as a result of the Inergy Propane Acquisition, we have expanded our operating territories in the midwest region of the United States. We sold approximately ~~283.8~~534.6 million gallons of propane and ~~28.5~~53.7 million gallons of fuel oil and refined fuels to retail customers during the year ended September ~~29, 2012.~~28, 2013. Together with our predecessor companies, we have been continuously engaged in the retail propane business since 1928.

We conduct our business principally through Suburban Propane, L.P., a Delaware limited partnership, which operates our propane business and assets (the “Operating Partnership”), and its direct and indirect subsidiaries. Our general partner, and the general partner of our Operating Partnership, is Suburban Energy Services Group LLC (the “General Partner”), a Delaware limited liability company whose sole member is the Chief Executive Officer of the Partnership. Since October 19, 2006, the General Partner has ~~had~~ no economic interest in either the Partnership or the Operating Partnership (which means that the General Partner is not entitled to any cash distributions of either partnership, nor to any cash payment upon the liquidation of either partnership, nor any other economic rights in either partnership) other than as a holder of 784 Common Units of the Partnership. Additionally, under the Third Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”) of the Partnership, there are no incentive distribution rights for the benefit of the General Partner. The Partnership owns (directly and indirectly) all of the limited partner interests in the Operating Partnership. The Common Units represent 100% of the limited partner interests in the Partnership.

On August 1, 2012 (the “Acquisition Date”), we acquired the sole membership interest in Inergy Propane, LLC, including certain wholly-owned subsidiaries of Inergy Propane LLC, and the assets of Inergy Sales and Service, Inc. (the “Inergy Propane Acquisition”). The acquired interests and assets are collectively referred to as “Inergy Propane.” As of the Acquisition Date, Inergy Propane consisted of the former retail propane assets and operations, as well as the assets and operations of the refined fuels business, of Inergy, L.P. (“Inergy”), a publicly traded limited ~~partnership.~~partnership at the time of the acquisition. On the Acquisition Date, Inergy Propane and its remaining wholly-owned subsidiaries which we acquired in the Inergy Propane Acquisition became subsidiaries of our Operating ~~Partnership.~~Partnership, but were merged into the Operating Partnership on April 30, 2013. The results of operations of Inergy Propane ~~currently markets its propane products under various regional brand names. As~~are included in the Partnership’s results of ~~its most recently completed fiscal year ended September 30, 2011 (prior to~~operations beginning on the Inergy Propane Acquisition), Inergy Propane sold approximately 325.6 million gallons of propane and 39.0 million gallons of fuel oil and refined fuels to retail customers through approximately 338 customer service centers in 33 states.Acquisition Date.

With the Inergy Propane Acquisition, we ~~have~~ effectively doubled the size of our customer base and have expanded our geographic reach into eleven (11) new states, including establishing a presence in portions of the midwest region of the United States. The Inergy Propane Acquisition is consistent with key elements of our business strategy to focus on businesses that complement our existing business segments and that can extend our presence in strategically attractive markets. This acquisition has provided, and will continue to provide, us with an opportunity to apply our operational expertise and customer-oriented initiatives to a much larger enterprise in order to enhance our growth prospects and cash flow profile. The total cost of the Inergy Propane Acquisition, as measured by the fair value of the total consideration was approximately $1.9 billion.

Direct and indirect subsidiaries of the Operating Partnership include Suburban Heating Oil Partners, LLC, which owns and operates the assets of our fuel oil and refined fuels business; Agway Energy Services, LLC, which owns and operates the assets of our natural gas and electricity business; and, Suburban Sales and Service, Inc., which conducts a portion of our service work and appliance and parts business. Our fuel oil and refined fuels, natural gas and electricity and services businesses are structured as either limited liability companies that are treated as corporations or corporate entities (collectively referred to as “Corporate Entities”) and, as such, are subject to corporate level income tax.

Suburban Energy Finance Corp., a direct 100%-owned subsidiary of the Partnership, was formed on November 26, 2003 to serve as co-issuer, jointly and severally with the Partnership, of the Partnership’s senior notes. Suburban Energy Finance Corp. has nominal assets and conducts no business operations.

In this Annual Report, unless otherwise indicated, the terms “Partnership,” “Suburban,” “we,” “us,” and “our” are used to refer to Suburban Propane Partners, L.P. and its consolidated subsidiaries, including the Operating Partnership. The Partnership and the Operating Partnership 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 atwww.sec.gov.

Upon written request or through an information request link from our website atwww.suburbanpropane.com, we will provide, without charge, copies of our Annual Report on Form 10-K for the year ended September ~~29, 2012,~~28, 2013, 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. The information contained on our website is not included as part of, or incorporated by reference into, this Annual Report on Form 10-K.

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

Internal Focus on Driving Operating Efficiencies, Right-Sizing Our Cost Structure and Enhancing Our Customer Mix. We focus internally on improving the efficiency of our existing operations, managing our cost structure and improving our customer mix. Through investments in our technology infrastructure, we continue to seek to improve operating efficiencies and the return on assets employed. We have developed a streamlined operating footprint and management structure to facilitate effective resource planning and decision making. Our internal efforts are particularly focused in the areas of route optimization, forecasting customer usage, inventory control, cash management and customer tracking. In connection with the Inergy Propane Acquisition, we have developed, and are implementing, a detailed integration plan to combine the best practices of the two companies while, at the same time, continuing to pursue efficiencies and operational excellence. Our strategy will include ~~executing~~continuing to execute on our integration plans and staying focused on providing exceptional service to the combined customer base. We will pursue opportunities to drive operational efficiencies across a broader geography. Our systems platform is advanced and scalable and we will seek to leverage that technology for enhanced routing, forecasting and customer relationship management, as well as ~~to centralize~~centralizing certain back office functions within the former Inergy Propane operations.

Growing Our Customer Base by Improving Customer Retention and Acquiring New Customers. We set clear objectives to focus our employees on seeking new customers and retaining existing customers by providing highly responsive customer service. We believe that customer satisfaction is a critical factor in the growth and success of our operations.“Our Business is Customer Satisfaction” is one of our core operating philosophies. We measure and reward our customer service centers based on a combination of profitability of the individual customer service center and net customer growth. We have made investments in training our people both on techniques to provide exceptional customer service to our existing customer base, as well as advanced sales training focused on growing our customer base.

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. We are very patient and deliberate in evaluating acquisition candidates. Consistent with this strategy, the Inergy Propane Acquisition, completed on August 1, 2012, was a transformative event for Suburban by expanding our geographic reach, doubling the size of our customer base and providing us with opportunities to achieve operational synergies by combining operations in overlapping territories and implementing our operating model and systems platform on a much larger business. During fiscal 2011 and 2010, we completed a total of five (5) acquisitions of mid-sized propane businesses in markets where we already had a strong presence. These acquisitions complemented our existing operations, expanded our customer base and, with our focus on operational efficiencies, provided synergies through the blending of operations and assets into our existing facilities.

Selective Disposition of Non-Strategic Assets. We continuously evaluate our existing facilities to identify opportunities to optimize our return on assets by selectively divesting operations in slower growing markets, generating proceeds that can be reinvested in markets that present greater opportunities for growth. Our objective is to maximize the growth and profit potential of all of our assets.

We manage and evaluate our operations in ~~four~~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 aby-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 ofstand-alone energy sources. Propane use falls into three broad categories:

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 powerover-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.

We distribute propane through a nationwide retail distribution network consisting of approximately 750 locations in 41 states as of September ~~29, 2012.~~28, 2013. Our operations are concentrated in the east and west coast regions of the United States, including Alaska and, as a result of the Inergy Propane Acquisition, we ~~have~~ expanded our operating territories into the midwest region of the United States. As of September ~~29, 2012,~~28, 2013, we serviced approximately ~~1,135,000~~1,062,000 propane customers. Typically, our customer service centers are located in suburban and rural areas where natural gas is not readily available. Generally, these customer service centers consist of an office, appliance showroom, warehouse and service facilities, with one or more 18,000 to 30,000 gallon storage tanks on the premises. Most of our residential customers receive their propane supply through an automatic delivery system. These deliveries are scheduled through computer technology, based upon each customer’s historical consumption patterns and prevailing weather conditions. Additionally, we offer our customers a budget payment plan whereby the customer’s estimated annual propane purchases and service contracts are paid for in a series of estimated equal monthly payments over a twelve-month period. From our customer service centers, we also sell, install and service equipment to customers who purchase propane from us including heating and cooking appliances, hearth products and supplies and, at some locations, propane fuel systems for motor vehicles.

We sell propane primarily to six customer markets: residential, commercial, industrial (including engine fuel), agricultural, other retail users and wholesale. Approximately ~~96%~~97% of the propane gallons sold by us in fiscal ~~2012~~2013 were to retail customers: ~~52%~~49% to residential customers, ~~25%~~29% to commercial customers, 8%6% to industrial customers, 4%5% to agricultural customers and ~~12%~~11% to other retail users. The balance of approximately 4%3% of the propane gallons sold by us in fiscal ~~2012~~2013 was for risk management activities and wholesale customers. No single customer accounted for 10% or more of our propane revenues during fiscal ~~2012.~~2013.

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.

Our propane supply is purchased from approximately 5665 oil companies and natural gas processors at approximately ~~155~~160 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 ~~2013.~~2014. During fiscal ~~2012,~~2013, Inergy Services (a subsidiary of Inergy) and Targa Liquids Marketing and Trade (“Targa”)~~, Enterprise Products Operating L.P. (“Enterprise”), Phillips 66 and Inergy Services (a subsidiary of Inergy)~~ provided approximately ~~16%, 13%, 11%~~34% and ~~11%~~12% of our total propane purchases, respectively. No other single supplier accounted for more than 10% of our propane purchases in fiscal 2013. In connection with the Inergy Propane Acquisition, we entered into a supply agreement with Inergy for the supply of propane to the majority of the acquired Inergy Propane operations through April ~~2013.~~2014. Pricing under the supply agreement with Inergy is similar to our existing annual supply arrangements in that it provides for formula pricing at the time of delivery based on major supply points. We expect ~~that~~ Inergy ~~will become~~to remain one of our largest propane suppliers in fiscal ~~2013.~~2014. 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 the aforementioned suppliers were interrupted, we would be able to secure adequate propane supplies from other sources without a material disruption of our operations. Nevertheless, the cost of acquiring such propane might be higher and, at least on a short-term basis, our margins could be affected. Approximately ~~98%~~99% of our total propane purchases were from domestic suppliers in fiscal ~~2012.~~2013.

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

We own and operate a large propane storage facility in California. We also operate smaller storage facilities in other locations and have rights to use storage facilities in additional locations. These storage facilities enable us to buy and store large quantities of propane particularly during periods of low demand, which generally occur during the summer months. This practice helps ensure a more secure supply of propane during periods of intense demand or price instability. As of September ~~29, 2012,~~28, 2013, the majority of our storage capacity in California was leased to third parties.

According to the ~~Energy Information Administration’s Short-Term Energy Outlook Model Documentation (August 2011),~~US Census Bureau’s 2012 American Community Survey, propane ranks as the fourth most important source of residential energy in the nation, with about 5% of all households using propane as their primary space heating fuel. This level has not changed materially over the previous two decades. As an energy source, propane competes primarily with natural gas, electricity and fuel oil, principally on the basis of price, availability and portability.

Propane is more expensive than natural gas on an equivalent British Thermal Unit (“BTU”) basis in locations serviced by natural gas, but it is an alternative or supplement to natural gas in rural and suburban areas where natural gas is unavailable or portability of product is required. Historically, the expansion of natural gas into traditional propane markets has been inhibited by the capital costs required to expand pipeline and retail distribution systems. Although the recent extension of natural gas pipelines to previously unserved geographic areas tends to displace propane distribution in those areas, we believe new opportunities for propane sales may arise as new neighborhoods are developed in geographically remote areas. However, over the last ~~year or so,~~few years, fewer new housing developments have been started in our service areas as a result of recent economic circumstances.

Propane has some relative advantages over other energy sources. For example, in certain geographic areas, propane is generally less expensive to use than electricity for space heating, water heating, clothes drying and cooking. Utilization of fuel oil is geographically limited (primarily in the northeast), and even in that region, propane and fuel oil are not significant competitors because of the cost of converting from one to the other.

In addition to competing with suppliers of other energy sources, our propane operations compete with other retail propane distributors. The retail propane industry is highly fragmented and competition generally occurs on a local basis with other large full-service multi-state propane marketers, thousands of smaller local independent marketers and farm cooperatives. Based on industry statistics contained in~~2010~~2011 Sales of Natural Gas Liquids and Liquefied Refinery Gases, as published by the American Petroleum Institute in ~~December 2011,~~February 2013, andLP/Gas Magazine dated February ~~2012,~~2013, the ten largest retailers, including us, account for approximately ~~39%~~35% of the total retail sales of propane in the United States. Each of our customer service centers operates in its own competitive environment because retail marketers tend to locate in close proximity to customers in order to lower the cost of providing service. Our typical customer service center has an effective marketing radius of approximately 50 miles, although in certain areas the marketing radius may be extended by one or more satellite offices. Most of our customer service centers compete with five or more marketers or distributors.

We market and distribute fuel oil, kerosene, diesel fuel and gasoline to approximately ~~79,000~~68,000 residential and commercial customers primarily in the northeast region of the United States. Sales of fuel oil and refined fuels for fiscal ~~2012~~2013 amounted to ~~28.5~~53.7 million gallons. Approximately ~~68%~~65% of the fuel oil and refined fuels gallons sold by us in fiscal ~~2012~~2013 were to residential customers, principally for home heating, 5%11% were to commercial customers, ~~1% were to agricultural~~ and 4%2% to other users. Sales of diesel and gasoline accounted for the remaining 22% of total volumes sold in this segment during fiscal ~~2012.~~2013. Fuel oil has a more limited use, compared to propane, and is used almost exclusively for space and water heating in residential and commercial buildings. We sell diesel fuel and gasoline to commercial and industrial customers for use primarily to operate motor vehicles.

Approximately ~~45%~~43% of our fuel oil customers receive their fuel oil under an automatic delivery system. These deliveries are scheduled through computer technology, based upon each customer’s historical consumption patterns and prevailing weather conditions. Additionally, we offer our customers a budget payment plan whereby the customer’s estimated annual fuel oil purchases are paid for in a series of estimated equal monthly payments over a twelve-month period. From our customer service centers, we also sell, install and service equipment to customers who purchase fuel oil from us including heating appliances.

Deliveries of fuel oil are usually made to customers by means of tankwagon trucks, which have capacities ranging from 2,500 gallons to 3,000 gallons. Fuel oil is pumped from the tankwagon truck into a stationary storage tank that is located on the customer’s premises, which is owned by the customer. The capacity of customer storage tanks ranges from approximately 275 gallons to approximately 1,000 gallons. No single customer accounted for 10% or more of our fuel oil revenues during fiscal ~~2012.~~2013.

We obtain fuel oil and other refined fuels in pipeline, truckload or tankwagon quantities, and have contracts with certain pipeline and terminal operators for the right to temporarily store fuel oil at 14 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 approximately 40 suppliers at approximately 8050 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 ~~2013.~~2014.

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

We market natural gas and electricity through our 100%-owned subsidiary, Agway Energy Services, LLC (“AES”), in the deregulated markets of New York and Pennsylvania primarily to residential and small commercial customers. Historically, local utility companies provided their customers with all three aspects of electric and natural gas service: generation, transmission and distribution. However, under deregulation, public utility commissions in several states are licensing energy service companies, such as AES, to act as alternative suppliers of the commodity to end consumers. In essence, we make arrangements for the supply of electricity or natural gas to specific delivery points. The local utility companies continue to distribute electricity and natural gas on their distribution systems. The business strategy of this business segment is to expand its market share by concentrating on growth in the customer base and expansion into other deregulated markets that are considered strategic markets.

We serve nearly ~~92,000~~87,000 natural gas and electricity customers in New York and Pennsylvania. During fiscal ~~2012,~~2013, we sold approximately ~~3.5~~4.2 million dekatherms of natural gas and ~~582.1~~550.6 million kilowatt hours of electricity through the natural gas and electricity segment. Approximately ~~81%~~82% of our customers were residential households and the remainder were small commercial and industrial customers. New accounts are obtained through numerous marketing and advertising programs, including telemarketing and direct mail initiatives. Most local utility companies have established billing service arrangements whereby customers receive a single bill from the local utility company which includes distribution charges from the local utility company, as well as product charges for the amount of natural gas or electricity provided by AES and utilized by the customer. We have arrangements with several local utility companies that provide billing and collection services for a fee. Under these arrangements, we are paid by the local utility company for all or a portion of customer billings after a specified number of days following the customer billing with no further recourse to AES.

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

We sell, install and service various types of whole-house heating products, air cleaners, humidifiers, hearth products and space heaters to the customers of our propane, fuel oil, natural gas and electricity businesses. Our supply needs are filled through supply arrangements with several large regional equipment manufacturers and distribution companies. Competition in this business segment is primarily with small, local heating and ventilation providers and contractors, as well as, to a lesser extent, other regional service providers. The focus of our ongoing service offerings are in support of the service needs of our existing customer base within our propane, refined fuels and natural gas and electricity business segments. Additionally, we have entered into arrangements with third-party service providers to complement and, in certain instances, supplement our existing service capabilities.

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

Weather conditions have a significant impact on the demand for our products, in particular propane, fuel oil and natural gas, for both heating and agricultural purposes. Many of our customers rely on propane, fuel oil or natural gas primarily as a heating source. Accordingly, the volume sold is directly affected by the severity of the winter weather in our service areas, which can vary substantially from year to year. In any given area, sustained warmer than normal temperatures ~~as was the case with the fiscal 2012 heating season throughout our operating territories,~~ 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.

We utilize a variety of trademarks and tradenames owned by us, including “Suburban Propane” and “Suburban Cylinder Express.” ~~Inergy Propane, which we acquired on August 1, 2012 in connection with~~As part of the Inergy Propane Acquisition, ~~conducts its business under~~we acquired a number of different tradenames, such as ~~“Pyrofax Energy” and “Modern Gas.~~“Yates Gas,” under which Inergy Propane conducted its business as of the Acquisition Date. Additionally, we hold rights to certain trademarks and tradenames, including ~~“Agway Propane,”~~ “Agway” ~~and “Agway Energy Products”~~ in connection with the distribution of petroleum-based fuel and sales and service of heating and ventilation products. We regard our trademarks, tradenames and other proprietary rights as valuable assets and believe that they have significant value in the marketing of our products and services.

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 hazardous materials and pollutants and establish standards for the handling, transportation, treatment, storage and disposal 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 as a potentially responsible party under CERCLA or comparable state statutes 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, and in the Inergy Propane Acquisition, 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, certain of the 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. With respect to certain of the properties acquired in the Inergy Propane Acquisition, Inergy is contractually obligated to indemnify us for the costs associated with the investigation, monitoring, remediation and/or resolution of identified conditions. As of September ~~29, 2012,~~28, 2013, we had accrued environmental liabilities of ~~$1.4~~$0.7 million representing the total estimated future liability for remediation and ~~monitoring.~~monitoring of all of our properties.

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, or the extent to which such additional liabilities would be subject to the contractual indemnification of Inergy.

National Fire Protection Association (“NFPA”) Pamphlet Nos. 54 and 58, which establish rules and procedures governing the safe handling of propane, or comparable regulations, have been adopted, in whole, in part or with state addenda, as the industry standard for propane storage, distribution and equipment installation and operation in all of the states in which we operate. In some states these laws are administered by state agencies, and in others they are administered on a municipal level.

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

With respect to the transportation of propane, distillates and gasoline by truck, we are subject to regulations promulgated under the Federal Motor Carrier Improvement 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 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, transportation 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. ~~Prior to the Inergy Propane Acquisition, we had 474~~We have 1,180 facilities registered with the DHS, of which ~~454~~1,161 facilities have been determined to be “Not a High Risk Chemical Facility”. ~~Twenty~~Nineteen facilities have been determined by DHS to be High Risk, Tier 4 (lowest level of security risk). Security Vulnerability Assessments for the 2019 facilities have been submitted to the DHS and ~~the DHS has reviewed 17 of them, requiring us to submit~~ Site Security Plans ~~for those facilities. We have not yet received DHS’ responses to these 17 submitted Site Security Plans. Pending DHS review,~~are being prepared when deemed necessary by the remaining 3 facilities may require Site Security Plans within 90 days of DHS notification, which we have not yet received. We are still evaluating the application of the DHS regulations to the facilities we recently acquired in the Inergy Propane Acquisition.DHS. Because our facilities are currently operating under the security programs developed under guidelines issued by the Department of Transportation, Department of Labor and Environmental Protection Agency, we do not anticipate that we will incur significant costs in order to comply with these DHS regulations.

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

Both Houses of the United States Congress also have considered adopting legislation to reduce emissions of GHGs. However, Congress has not yet enacted federal climate change legislation.

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

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

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

The Dodd-Frank Act requires the Commodity Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations relating to, among other things, swaps, participants in the derivatives markets, clearing of swaps and reporting of swap transactions. In general, the Dodd-Frank Act subjects swap transactions and participants to greater regulation and supervision by the CFTC and the SEC and will require many swaps to be cleared through a registered CFTC- or SEC-clearing facility and executed on a designated exchange or swap execution facility.

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

The new legislation and regulations promulgated thereunder could increase the operational and transactional cost of derivatives contracts and affect the number and/or creditworthiness of counterparties available to us.

As of September ~~29, 2012,~~28, 2013, we had ~~4,144~~3,933 full time employees, of whom ~~656~~683 were engaged in general and administrative activities (including fleet maintenance), 4439 were engaged in transportation and product supply activities and ~~3,444~~3,211 were customer service center employees. As of September ~~29, 2012, 163~~28, 2013, 127 of our employees were represented by 2116 different local chapters of labor unions. We believe that our relations with both our union andnon-union employees are satisfactory. From time to time, we hire temporary workers to meet peak seasonal demands.

Investing in our common units involves a high degree of risk. The most significant risks include those described below; however, additional risks that we currently do not know about may also impair our business operations. You should carefully consider the following risk factors, as well as the other information in this Annual Report. If any of the following risks actually occurs, our business, results of operations and financial condition could be materially adversely affected. In this case, the trading price of our common units would likely decline and you might lose part or all of the value in our common units. 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.

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

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

Actual weather conditions can vary substantially from year to year, significantly affecting our financial performance. For example, average temperatures in our service territories were ~~14%~~4%, 1%14% and 5%1% warmer than normal for fiscal 2013, fiscal 2012 and fiscal 2011, ~~and fiscal 2010,~~ respectively, as measured by the number of heating degree days reported by the National Oceanic and Atmospheric Administration (“NOAA”). In addition, for the six month period from October 2011 through March 2012, average temperature in our service territories was 14% warmer than normal, which period has been reported by NOAA as the warmest on record in the contiguous United States. Furthermore, variations in weather in one or more regions in which we operate can significantly affect the total volume of propane, fuel oil and other refined fuels and natural gas we sell and, consequently, our results of operations. Variations in the weather in the northeast, where we have a greater concentration of propane accounts and substantially all of our fuel oil and natural gas operations, generally have a greater impact on our operations than variations in the weather in other markets. We can give no assurance that the weather conditions in any quarter or year will not have a material adverse effect on our operations, or that our available cash will be sufficient to pay principal and interest on our indebtedness and distributions to Unitholders.

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

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

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

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

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

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

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

In addition to competing with other sources of energy, our propane and fuel oil businesses compete with other distributors of those respective products principally on the basis of price, service and availability. Competition in the retail propane business is highly fragmented and generally occurs on a local basis with other large full-service multi-state propane marketers, thousands of smaller local independent marketers and farm cooperatives. Our fuel oil business competes with fuel oil distributors offering a broad range of services and prices, from full service distributors to those offering delivery only. In addition, our existing fuel oil customers, unlike our existing propane customers, generally own their own tanks, which can result in intensified competition for these customers.

As a result of the highly competitive nature of the retail propane and fuel oil businesses, our growth within these industries depends on our ability to acquire other retail distributors, open new customer service centers, add new customers and retain existing customers. We can give no assurance that we will be able to acquire other retail distributors, add new customers and retain existing customers. For additional risks relating to customer retention, see “—Risks Related to the Inergy Propane Acquisition and the Related Transactions – We may not be able to successfully integrate Inergy’s Propane’s operations with our operations, which could cause our business to suffer.”

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

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

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

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

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

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

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

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

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

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

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

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

Our operations are subject to all operating hazards and risks normally associated with handling, storing and delivering combustible liquids such as propane, fuel oil and other refined fuels. We have been, and are likely to continue to be, a defendant in various legal proceedings and litigation arising in the ordinary course of business, both as a result of these operating hazards and risks and as a result of other aspects of our business. We are self-insured for general and product, workers’ compensation and automobile liabilities up to predetermined amounts above which third-party insurance applies. We cannot guarantee that our insurance will be adequate to protect us from all material expenses related to potential future claims for personal injury and property damage or that these levels of insurance will be available at economical prices, or that all legal matters that arise will be covered by our insurance programs.

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

The retail propane and fuel oil industries are mature. We expect overall demand for propane and fuel oil to be relatively flat to moderately declining over the next several years. With respect to our retail propane business, it may be difficult for us to increase our aggregate number of retail propane customers except through acquisitions. As a result, we expect the success of our financial performance to depend, in part, upon our ability to acquire other retail propane and fuel oil distributors or other energy-related businesses and to successfully integrate them into our existing operations and to make cost saving changes. The competition for acquisitions is intense and we can make no assurance that we will be able to acquire other propane and fuel oil distributors or other energy-related businesses on economically acceptable terms or, if we do, to integrate the acquired operations effectively.

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

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

Both Houses of the United States Congress also have considered adopting legislation to reduce emissions of GHGs. However, Congress has not yet enacted federal climate change legislation.

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

The Dodd-Frank Act requires the Commodity Futures Trading Commission (the “CFTC”) and the ~~Securities and Exchange Commission (the “SEC”)~~SEC to promulgate rules and regulations relating to, among other things, swaps, participants in the derivatives markets, clearing of swaps and reporting of swap transactions. In general, the Dodd-Frank Act subjects swap transactions and participants to greater regulation and supervision by the CFTC and the SEC and will require many swaps to be cleared through a CFTC- or SEC-registered clearing facility and executed on a designated exchange or swap execution facility.

We depend on particular management information systems to effectively manage all aspects of our delivery of propane.

We depend on our management information systems to process orders, manage inventory and accounts receivable collections, maintain distributor and customer information, maintain cost-efficient operations and assist in delivering our products on a timely basis. In addition, our staff of management information systems professionals relies heavily on the support of several key personnel and vendors. Any disruption in the operation of those management information systems, loss of employees knowledgeable about such systems, termination of our relationship with one or more of these key vendors or failure to continue to modify such systems effectively as our business expands could negatively affect our business.

We may not be able to successfully integrate Inergy Propane’s operations with our operations, which could cause our business to suffer.

In order to obtain all of the anticipated benefits of the Inergy Propane Acquisition, we will need to combine and integrate the businesses and operations of Inergy Propane with ours. ~~The~~Although we have developed, and are implementing, a detailed integration plan, the combination of two large businesses is a complex and costly process. ~~As a result of the Inergy Propane Acquisition, we~~We will be required to continue to devote significant management attention and resources to integrating the business practices and operations of Suburban and Inergy Propane. ~~The~~Although we believe that it has not yet done so, the integration process may, in the future, divert the attention of our executive officers and management from day-to-day operations and disrupt the business of Suburban and, if implemented ineffectively, may preclude realization of the expected benefits of the transaction.

Our failure to meet the challenges involved in successfully ~~integrating~~completing the integration of Inergy Propane’s operations with our operations or otherwise to realize any of the anticipated benefits of the Inergy Propane Acquisition could adversely affect our results of operations. In addition, the overall integration of Suburban and Inergy Propane may yet result in unanticipated problems, expenses, liabilities and competitive responses. The loss of customer relationships may be above historical norms not only with respect to existing Suburban customers but also as to the Inergy Propane customers who ~~will~~are now bebeing serviced by Suburban. ~~We expect the~~Although not yet experienced to any significant degree, possible difficulties ~~of combining~~that may yet arise from our continuing efforts to combine our two operations tocould include, among others:

In addition, even if we are able to successfully ~~integrate~~complete the integration of our businesses and operations, we may not fully realize the expected benefits of the Inergy Propane Acquisition within the intended time frame, or at all. Further, our post-acquisition results of operations may be affected by factors different from those existing prior to the Inergy Propane Acquisition and may suffer as a result of the Inergy Propane Acquisition. As a result, we can give no assurance that the combination of our business and operations with Inergy Propane will result in the realization of the full benefits anticipated from the Inergy Propane Acquisition.

We incurred and continue to incur substantial expenses related to the integration of Inergy ~~Propane Acquisition.~~Propane.

We have incurred and expect to continue to incur substantial expenses in connection with the Inergy Propane Acquisition and integrating the business, operations, networks, systems, technologies, policies and procedures of Suburban and Inergy Propane. There are a large number of systems that must be integrated, including billing, management information, information systems, purchasing, accounting and finance, sales, payroll and benefits, fixed assets, lease administration and regulatory compliance. Although Suburban has assumed that a certain level of transaction and integration expenses would be incurred, there are a number of factors beyond our control that could affect the total amount or the timing of these integration expenses. ~~Many~~Although integration expenses have been, to date, within the expected range, many of the expenses ~~that will~~yet to be incurred are, by their nature, ~~are~~ difficult to accurately estimate ~~accurately~~ at the present time. Due to these factors, the total transaction and integration expenses associated with the Inergy Propane Acquisition could, particularly in the near term, exceed the savings that we expect to achieve from the elimination of duplicative expenses and the realization of economies of scale and cost savings related to the integration of the businesses. As a result of these expenses, Suburban has taken, and expects to continue to take, charges against its earnings relating to the acquisition and integration of Inergy Propane. The charges relating to the acquisition and integration of Inergy Propane have been and expect to continue to be significant, although the aggregate amount and timing of all such charges are uncertain at present.

The ~~completion and~~ integration of ~~the~~ Inergy Propane ~~Acquisition~~ could cause disruptions in ~~ours and Inergy Propane’s businesses,~~our business, which could have an adverse effect on both ~~businesses~~our business and financial results.

In response to the ~~announcement, completion and~~ integration activities related to the Inergy Propane Acquisition, our or Inergy Propane’s customers may delay or defer purchasing decisions, or choose to switch to another competitor for the supply of propane. Any such delay, deferral or change of supplier by customers could negatively affect our business and results of operations. Similarly, our ~~current and prospective~~ employees may experience uncertainty about their future roles with us until ~~full integration of the~~ Inergy Propane ~~Acquisition~~ is ~~completed.~~fully integrated. This may adversely affect our ability to attract and retain key management, marketing and technical personnel.

~~Following~~During and following the integration of Inergy Propane, ~~Acquisition,~~ we may be unable to retain key employees.

Our future success ~~after the Inergy Propane Acquisition~~ will depend in part upon our ability to retain key Suburban employees, including employees of Inergy Propane who became Suburban employees upon completion of the Inergy Propane Acquisition. Key employees may hereafter depart ~~at some point following the Inergy Propane Acquisition~~ because of issues relating to the uncertainty and difficulty of integration, a desire not to remain with us ~~following the Inergy Propane Acquisition~~ or otherwise. Accordingly, no assurance can be given that Suburban will be able to retain key employees to the same extent as in the past.

~~Our future results will suffer if we do not effectively manage our expanded operations following the Inergy Propane Acquisition.~~

Following the Inergy Propane Acquisition, we may continue to expand our operations through additional acquisitions and other strategic acquisitions, some of which will involve complex challenges. Our future success will depend, in part, upon our ability to manage our expansion opportunities, which pose substantial challenges for us to integrate new operations into our existing business in an efficient and timely manner, and upon our ability to successfully monitor our operations, costs, regulatory compliance and service quality and to maintain other necessary internal controls. We cannot assure you that our expansion or acquisition opportunities will be successful or that we will realize our expected operating efficiencies, cost savings, revenue enhancements, synergies or other benefits.

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:

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

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

As of September ~~29, 2012,~~28, 2013, our long-term debt borrowings consisted of $496.6 million in aggregate principal amount of ~~unregistered~~ 7.5% senior notes due October 1, 2018 (excluding unamortized premium of ~~$33.4~~$28.6 million), $250.0 million in aggregate principal amount of 7.375% senior notes due March 15, 2020 (excluding unamortized discount of ~~$1.6~~$1.4 million), ~~$503.4~~$346.2 million in aggregate principal amount of ~~unregistered~~ 7.375% senior notes due August 1, 2021 (excluding unamortized premium of ~~$40.3~~$25.3 million), and $100.0 million under our senior secured 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 holders of our common units if there is, or after giving effect to such distribution, there would be, an event of default under the indentures governing the senior notes. The amount of distributions that we may make to holders of our common units is limited by the senior notes, and the amount of distributions that the Operating Partnership may make to us is limited by our revolving credit facility.

The revolving credit facility and the senior notes both contain various restrictive and affirmative covenants applicable to us and the Operating Partnership, respectively, including (i) restrictions on the incurrence of additional indebtedness, and (ii) restrictions on certain liens, investments, guarantees, loans, advances, payments, mergers, consolidations, distributions, sales of assets and other transactions. The revolving credit facility contains certain financial covenants: (a) requiring our consolidated interest coverage ratio, as defined, to be not less than ~~2.5~~2.0 to 1.0 as of the end of any fiscal ~~quarter;~~quarter (and commencing with the third quarter of fiscal 2014, such minimum ratio will be 2.5 to 1.0); (b) prohibiting our total consolidated leverage ratio, as defined, from being greater than 4.75 to 1.0 (or 5.0 to 1.0 during an acquisition period, as defined in the credit agreement governing the credit facility) 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 indentures governing the senior notes, 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 ~~29, 2012.~~28, 2013.

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. As interest expense increases (whether due to an increase in interest rates and/or the size of aggregate outstanding debt), our ability to fund common unit distributions may be impacted, depending on the level of revenue generation, which is not assured.

A Board of Supervisors governs our operations. Unitholders have only limited voting rights on matters affecting our business, including the right to elect the members of our Board of Supervisors every three years and the right to vote on the removal of the general partner.

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

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

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:

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.

Our tax treatment depends on our status as a partnership for U.S. 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 U.S. federal income tax purposes. If less than 90% of the gross income of a publicly traded partnership, such as Suburban Propane Partners, L.P., for any taxable year is “qualifying income” within the meaning of Section 7704 of the Internal Revenue Code, that partnership will be taxable as a corporation for U.S. federal income tax purposes for that taxable year and all subsequent years.

If we were treated as a corporation for U.S. federal income tax purposes, then we would pay U.S. federal income tax on our income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay additional state income tax at varying rates. Because a tax would be imposed upon us as a corporation, our cash available for distribution to Unitholders would be substantially reduced. Treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to Unitholders and thus would likely result in a substantial reduction in the value of our Common Units.

The tax treatment of publicly traded partnerships or an investment in our Common Units could be subject to potential legislative, judicial or administrative changes and differing interpretations thereof, possibly on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including Suburban Propane Partners, L.P., or an investment in our Common Units may be modified by legislative, judicial or administrative changes and differing interpretations thereof at any time. Any modification to the U.S. federal income tax laws or interpretations thereof may or may not be applied retroactively. Moreover, any such modification could make it more difficult or impossible for us to meet the exception that allows publicly traded partnerships that generate qualifying income to be treated as partnerships (rather than as corporations) for U.S. federal income tax purposes, affect or cause us to change our business activities, or affect the tax consequences of an investment in our Common Units. For example, legislation proposed by members of Congress and the President has considered substantive changes to the definition of qualifying income. One of the requirements for such classification is that at least 90% of our gross income for each taxable year has been and will be “qualifying income” within the meaning of Section 7704 of the Internal Revenue Code. Whether we will continue to be classified as a partnership in part depends on our ability to meet this qualifying income test in the future. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our 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.

A successful IRS contest of the U.S. 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 U.S. 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, a Unitholder is required to pay U.S. federal income taxes and state and local income taxes on its allocable share of our income, without regard to whether we make cash distributions to the Unitholder. 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 U.S. 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 U.S. federal income tax returns and pay tax on their share of our taxable income. Tax-exempt organizations and foreign persons should consult, and should depend on, their own tax advisors in analyzing the U.S. federal, state, local and foreign income tax and other tax consequences of the acquisition, ownership or disposition of Common Units.

The ability of a Unitholder to deduct its share of our losses may be limited.

Various limitations may apply to the ability of a Unitholder to deduct its share of our losses. For example, in the case of taxpayers subject to the passive activity 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. Such unused losses may be deducted when the Unitholder disposes of its entire investment in us in a fully taxable transaction with an unrelated party, such as a sale by a Unitholder of all of its Common Units in the open market. A Unitholder’s share of any net passive income may be offset by unused losses from us carried over from prior years, but not by losses from other passive activities, including losses from other publicly-traded partnerships.

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

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

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

We intend to furnish to each Unitholder, ~~with~~within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1 that sets forth its allocable share of income, gains, losses and ~~deductions.~~deductions for our preceding taxable year. 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 that may be inconsistent with Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to a Unitholder. It also could affect the timing of these tax benefits or the amount of gain from the sale of Common Units, and could have a negative impact on the value of our Common Units or result in audit adjustments to a Unitholder’s income tax return.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our Common Units each month based upon the ownership of our Common Units on the first day of each month, instead of on the basis of the date a particular Common Unit is transferred. The U.S. Treasury Department has issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferors and transferees of our common units. However, if the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our Unitholders.

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

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

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have terminated as a partnership for U.S. federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Our termination 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. In the case of a Unitholder reporting on a taxable year other than the calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our treatment as a partnership for U.S. federal income tax purposes, but instead, after our termination we would be treated as a new partnership for U.S. federal income tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred.

In addition to U.S. 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 U.S. federal, state and local income tax returns that may be required of each Unitholder.

A Unitholder whose Common Units are loaned to a “short seller” to cover a short sale of Common Units may be considered as having disposed of those Common Units. If so, that Unitholder would no longer be treated for tax purposes as a partner with respect to those Common Units during the period of the loan and may recognize gain or loss from the disposition.

Because there is no tax concept of loaning a partnership interest, a Unitholder whose Common Units are loaned to a “short seller” to cover a short sale of Common Units may be considered as having disposed of the loaned Common Units. In that case, a Unitholder may no longer be treated for tax purposes as a partner with respect to those Common Units during the period of the loan to the short seller and may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those Common Units may not be reportable by the Unitholder and any cash distribution received by the Unitholder as to those Common Units could be fully taxable as ordinary income. Unitholders desiring to ensure their status as partners and avoid the risk of gain recognition from a loan to a short seller should consult their own tax advisors to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their Common Units.

As of September ~~29, 2012,~~28, 2013, we owned approximately 70% 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 ~~29, 2012,~~28, 2013, we had a fleet of 2919 transport truck tractors, of which we owned ~~21,~~12, and 23 railroad tank cars, of which we owned none. In addition, as of September ~~29, 2012~~28, 2013 we had ~~1,707~~1,466 bobtail and rack trucks, of which we owned ~~57.5%~~56%, ~~184~~150 fuel oil tankwagons, of which we owned ~~61.4%~~71%, and ~~2,019~~1,587 other delivery and service vehicles, of which we owned ~~63.7%~~62%. We lease the vehicles we do not own. As of September ~~29, 2012,~~28, 2013, we also owned ~~1,132,099~~981,468 customer propane storage tanks with typical capacities of 100 to 500 gallons, ~~64,291~~83,890 customer propane storage tanks with typical capacities of over 500 gallons and ~~381,179~~304,390 portable propane cylinders with typical capacities of five to ten gallons.

Our operations are subject to operating hazards and risks normally incidental to handling, storing and delivering combustible liquids such as propane. We have been, and will continue to be, a defendant in various legal proceedings and litigation as a result of these operating hazards and risks, and as a result of other aspects of our business. In this last regard, we currently are a defendant in suits in two states, including one class action and another putative class action in which the court has denied class certification without prejudice. We believe both such suits are without merit. The class action alleges several claims relating to two fees charged by us in connection with our residential propane business in California. During the fourth quarter of fiscal 2012, we entered into an agreement to settle ~~that~~a California action, in which were alleged several claims relating to two fees charged by us, on a classwide basis in return for the payment of a monetary sum and certain non-monetary consideration, and established an accrual of $4.5 million for the estimated cost of the settlement. ~~The~~This settlement, entered into to avoid both the continued expenses and burden of defending that action and the uncertainty inherent in all litigation, was approved by the trial court ~~granted preliminary approval~~in May 2013, and we completed distribution of the ~~proposed~~ settlement ~~on November 19, 2012.~~proceeds to the class members in the fourth quarter of fiscal 2013. We are currently a defendant in a putative class action in which the court has denied class certification without prejudice. We believe such suit is without merit. In the putative class action, we have been successful in eliminating several of the claims such that only certain contractual and consumer statute claims remain. The subject matter jurisdiction of the court to adjudicate certain of the contractual claims is on appeal. We are contesting this putative class action vigorously and have determined, based on the allegations and discovery to date, that no reserve for a loss contingency other than for legal defense fees and expenses is required. We are unable to reasonably estimate the possible loss or range of loss, if any, arising from this litigation.

(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 ~~26, 2012,~~25, 2013, there were ~~778~~706 Unitholders of record (based on the number of record holders and nominees for those Common Units held in street name). The following table presents, for the periods indicated, the high and low sales prices per Common Unit, as reported on the NYSE, and the amount of quarterly cash distributions declared and paid per Common Unit in respect of each quarter.


					Cash Distribution						Cash Distribution
	Common Unit Price Range				Declared per		Common Unit Price Range				Declared per
	High		Low		Common Unit		High		Low		Common Unit
Fiscal 2013
First Quarter							$	44.82	$	36.69	$	0.8750
Second Quarter								44.80		38.09		0.8750
Third Quarter								50.25		41.93		0.8750
Fourth Quarter								49.50		44.21		0.8750
Fiscal 2012
First Quarter	$	49.19	$	44.50	$	0.8525	$	49.19	$	44.50	$	0.8525
Second Quarter		48.25		40.25		0.8525		48.25		40.25		0.8525
Third Quarter		44.52		34.58		0.8525		44.52		34.58		0.8525
Fourth Quarter		45.61		36.75		0.8525		45.61		36.75		0.8525

Fiscal 2011
First Quarter	$	57.24	$	51.50	$	0.8525
Second Quarter		58.99		49.30		0.8525
Third Quarter		57.89		49.90		0.8525
Fourth Quarter		53.23		40.25		0.8525

We make quarterly distributions to our partners in an aggregate amount equal to our Available Cash (as defined in our Partnership Agreement) with respect to such quarter. Available Cash generally means all cash on hand at the end of the fiscal quarter plus all additional cash on hand as a result of borrowings subsequent to the end of such quarter less cash reserves established by the Board of Supervisors in its reasonable discretion for future cash requirements. The amount of distributions that we may make to holders of our Common Units is limited by the senior notes, and the amount of distributions that the Operating Partnership may make to us is limited by our revolving credit facility. See “Risk Factors—We have substantial indebtedness. Our debt agreements may limit our ability to make distributions to Unitholders, as well as our financial flexibility” and “Management’s Discussion and Analysis—Liquidity and Capital Resources.”

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

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


	Year Ended															Year Ended
	September			September			September			September			September			September			September			September			September			September
	29, 2012 (a)			24, 2011			25, 2010			26, 2009			27, 2008			28, 2013			29, 2012 (a)			24, 2011			25, 2010			26, 2009
Statement of Operations Data
Revenues	$	1,063,458		$	1,190,552		$	1,136,694		$	1,143,154		$	1,574,163		$	1,703,606		$	1,063,458		$	1,190,552		$	1,136,694		$	1,143,154
Costs and expenses		1,002,641			1,045,324			980,508			932,539			1,424,035			1,526,630			1,003,885			1,047,324			980,508			932,539
Acquisition-related costs (b)		17,916			—			—			—			—			—			17,916			—			—			—
Severance charges (c)		—			2,000			—			—			—
Pension settlement charge (d)		—			—			2,818			—			—
Pension settlement charge (c)																	—			—			—			2,818			—
Operating income		42,901			143,228			153,368			210,615			150,128			176,976			41,657			143,228			153,368			210,615
Interest expense, net		38,633			27,378			27,397			38,267			37,052			95,427			38,633			27,378			27,397			38,267
Loss on debt extinguishment (e)		2,249			—			9,473			4,624			—
Loss on debt extinguishment (d)																	2,144			2,249			—			9,473			4,624
Provision for income taxes		137			884			1,182			2,486			1,903			607			137			884			1,182			2,486
Income from continuing operations		1,882			114,966			115,316			165,238			111,173
Discontinued operations:
Gain on disposal of discontinued operations (f)		—			—			—			—			43,707
Net income		1,882			114,966			115,316			165,238			154,880			78,798			638			114,966			115,316			165,238
Income from continuing operations per Common Unit—basic		0.05			3.24			3.26			4.99			3.39
Net income per Common Unit—basic (g)		0.05			3.24			3.26			4.99			4.72
Net income per Common Unit—diluted (g)		0.05			3.22			3.24			4.96			4.70
Net income per Common Unit—basic (e)																	1.35			0.02			3.24			3.26			4.99
Net income per Common Unit—diluted (e)																	1.34			0.02			3.22			3.24			4.96
Cash distributions declared per unit	$	3.41		$	3.41		$	3.35		$	3.26		$	3.09		$	3.50		$	3.41		$	3.41		$	3.35		$	3.26

Balance Sheet Data
Cash and cash equivalents	$	134,317		$	149,553		$	156,908		$	163,173		$	137,698		$	107,232		$	134,317		$	149,553		$	156,908		$	163,173
Current assets		338,280			297,822			296,427			307,556			359,551			293,322			337,515			297,822			296,427			307,556
Total assets		2,884,448			956,459			970,914			978,168			1,036,367			2,727,987			2,883,850			956,459			970,914			978,168
Current liabilities		253,715			151,514			164,514			181,930			226,780			233,894			253,715			151,514			164,514			181,930
Total debt		1,422,078			348,169			347,953			349,415			531,772			1,245,237			1,422,078			348,169			347,953			349,415
Total liabilities		1,792,705			598,241			608,258			620,632			818,472			1,598,861			1,793,351			598,241			608,258			620,632
Partners’ capital—Common Unitholders	$	1,152,850		$	418,134		$	419,882		$	418,824		$	262,050		$	1,176,479		$	1,151,606		$	418,134		$	419,882		$	418,824

Statement of Cash Flows Data
Cash provided by (used in)
Operating activities	$	110,973		$	132,786		$	155,797		$	246,551		$	120,517		$	214,306		$	110,973		$	132,786		$	155,797		$	246,551
Investing activities		(239,758	)		(19,505	)		(30,111	)		(16,852	)		36,630			(14,663	)		(239,758	)		(19,505	)		(30,111	)		(16,852	)
Financing activities	$	113,549		$	(120,636	)	$	(131,951	)	$	(204,224	)	$	(116,035	)	$	(226,728	)	$	113,549		$	(120,636	)	$	(131,951	)	$	(204,224	)

Other Data
Depreciation and amortization	$	45,790		$	35,628		$	30,834		$	30,343		$	28,394		$	130,384		$	47,034		$	35,628		$	30,834		$	30,343
EBITDA (h)		86,442			178,856			174,729			236,334			222,229
Adjusted EBITDA (h)		108,536			179,425			192,420			239,245			220,465
Capital expenditures—maintenance and growth (i)	$	17,476		$	22,284		$	19,131		$	21,837		$	21,819
EBITDA (f)																	305,216			86,442			178,856			174,729			236,334
Adjusted EBITDA (f)																	329,253			108,536			179,425			192,420			239,245
Capital expenditures—maintenance and growth (g)																$	27,823		$	17,476		$	22,284		$	19,131		$	21,837
Retail gallons sold
Propane		283,841			298,902			317,906			343,894			386,222			534,621			283,841			298,902			317,906			343,894
Fuel oil and refined fuels		28,491			37,241			43,196			57,381			76,515			53,710			28,491			37,241			43,196			57,381

(b)	Due to the Inergy Propane Acquisition on August 1, 2012 we recorded acquisition-related costs of $17.9 million during fiscal 2012. These costs were primarily attributable to investment banker, legal, accounting and other consulting fees.

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


	Fiscal			Fiscal			Fiscal			Fiscal			Fiscal			Fiscal			Fiscal			Fiscal			Fiscal			Fiscal
	2012			2011			2010			2009			2008			2013			2012			2011			2010			2009
Net income	$	1,882		$	114,966		$	115,316		$	165,238		$	154,880		$	78,798		$	638		$	114,966		$	115,316		$	165,238
Add:
Provision for income taxes		137			884			1,182			2,486			1,903			607			137			884			1,182			2,486
Interest expense, net		38,633			27,378			27,397			38,267			37,052			95,427			38,633			27,378			27,397			38,267
Depreciation and amortization		45,790			35,628			30,834			30,343			28,394			130,384			47,034			35,628			30,834			30,343

EBITDA		86,442			178,856			174,729			236,334			222,229			305,216			86,442			178,856			174,729			236,334
Unrealized (non-cash) (gains) losses on changes in fair value of derivatives		(4,649	)		(1,431	)		5,400			(1,713	)		(1,764	)
Acqusition-related costs		17,916			—			—			—			—
Unrealized (non-cash) losses (gains) on changes in fair value of derivatives																	4,318			(4,649	)		(1,431	)		5,400			(1,713	)
Integration-related costs																	10,575			—			—			—			—
Multi-employer pension plan withdrawal charge																	7,000			—			—			—			—
Loss on debt extinguishment																	2,144			2,249			—			9,473			4,624
Acquisition-related costs																	—			17,916			—			—			—
Loss on legal settlement		4,500			—			—			—			—			—			4,500			—			—			—
Loss on debt extinguishment		2,249			—			9,473			4,624			—
Loss on asset disposal		2,078			—			—			—			—			—			2,078			—			—			—
Severance charges		—			2,000			—			—			—			—			—			2,000			—			—
Pension settlement charge		—			—			2,818			—			—			—			—			—			2,818			—

Adjusted EBITDA		108,536			179,425			192,420			239,245			220,465			329,253			108,536			179,425			192,420			239,245
Add (subtract):
Provision for income taxes - current		(137	)		(884	)		(1,182	)		(1,101	)		(626	)
Provision for income taxes—current																	(607	)		(137	)		(884	)		(1,182	)		(1,101	)
Interest expense, net		(38,633	)		(27,378	)		(27,397	)		(38,267	)		(37,052	)		(95,427	)		(38,633	)		(27,378	)		(27,397	)		(38,267	)
Unrealized (non-cash) gains (losses) on changes in fair value of derivatives		4,649			1,431			(5,400	)		1,713			1,764
Unrealized (non-cash) (losses) gains on changes in fair value of derivatives																	(4,318	)		4,649			1,431			(5,400	)		1,713
Integration-related costs																	(10,575	)		—			—			—			—
Multi-employer pension plan withdrawal charge																	(7,000	)		—			—			—			—
Acquisition-related costs																	—			(17,916	)		—			—			—
Loss on legal settlement																	—			(4,500	)		—			—			—
Severance charges		—			(2,000	)		—			—			—			—			—			(2,000	)		—			—
Acqusition-related costs		(17,916	)		—			—			—			—
Loss on legal settlement		(4,500	)		—			—			—			—
Compensation cost recognized under Restricted Unit Plans		4,059			3,922			4,005			2,396			2,156
Compensation cost recognized under
Restricted Unit Plans																	3,888			4,059			3,922			4,005			2,396
(Gain) loss on disposal of property, plant and equipment, net		(727	)		(2,772	)		38			(650	)		(2,252	)		(3,543	)		(727	)		(2,772	)		38			(650	)
Gain on disposal of discontinued operations		—			—			—			—			(43,707	)
Changes in working capital and other assets and liabilities		55,642			(18,958	)		(6,687	)		43,215			(20,231	)		2,635			55,642			(18,958	)		(6,687	)		43,215

Net cash provided by operating activities	$	110,973		$	132,786		$	155,797		$	246,551		$	120,517		$	214,306		$	110,973		$	132,786		$	155,797		$	246,551

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.

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.

The level of profitability in the retail propane, fuel oil, natural gas and electricity businesses is largely dependent on the difference between retail sales price and product cost. The unit cost of our products, particularly propane, fuel oil and natural gas, is subject to volatility as a result of supply and demand dynamics or other market conditions, including, but not limited to, economic and political factors impacting crude oil and natural gas supply or pricing. We enter into product supply contracts that are generally one-year agreements subject to annual renewal, and also purchase product on the open market. We attempt to reduce price risk by pricing product on a short-term basis. Our propane supply contracts typically provide for pricing based upon index formulas using the posted prices established at major supply points such as Mont Belvieu, Texas, or Conway, Kansas (plus transportation costs) at the time of delivery.

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

Product cost changes can occur rapidly over a short period of time and can impact profitability. There is no assurance that we will be able to pass on product cost increases fully or immediately, particularly when product costs increase rapidly. Therefore, average retail sales prices can vary significantly from year to year as product costs fluctuate with propane, fuel oil, crude oil and natural gas commodity market conditions. In addition, periods of sustained higher commodity prices can lead to customer conservation, resulting in reduced demand for our product.

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

Weather 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, ~~as was the case with the fiscal 2012 heating season,~~ 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.

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, options and swap agreements with third parties, and use futures and options contracts traded on the New York Mercantile Exchange (“NYMEX”) to purchase and sell propane, fuel oil and crude oil at fixed prices in the future. The majority of the futures, forward and options 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. In addition, we sell propane and fuel oil to customers at fixed prices, and enter into ~~swap agreements~~derivative instruments to hedge a portion of our exposure to fluctuations in commodity prices as a result of selling the fixed price contracts. Forward contracts are generally settled physically at the expiration of the contract whereas futures, options and swap contracts are generally settled in cash at the expiration of the contract. Although we use derivative instruments to reduce the effect of price volatility associated with priced physical inventory and forecasted transactions, we do not use derivative instruments for speculative trading purposes. Risk management activities are monitored by an internal Commodity Risk Management Committee, made up of five members of management and reporting to our Audit Committee, through enforcement of our Hedging and Risk Management Policy.

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

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

Allowances for Doubtful Accounts. We maintain allowances for doubtful accounts for estimated losses resulting from the inability of our customers to make required payments. We estimate our allowances for doubtful accounts using a specific reserve for known or anticipated uncollectible accounts, as well as an estimated reserve for potential future uncollectible accounts taking into consideration our historical write-offs. If the financial condition of one or more of our customers were to deteriorate resulting in an impairment in their ability to make payments, additional allowances could be required. As a result of our large customer base, which is comprised of more than 1.2 million 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. With other assumptions held constant, an increase or decrease of 100 basis points in the discount rate would have an immaterial impact on net pension and postretirement benefit costs. See “Liquidity and Capital Resources—Pension Plan Assets and Obligations” below for additional disclosure regarding pension benefits.

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

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

Fair Values of Acquired Assets and Liabilities. From time to time, we enter into material business combinations. In accordance with accounting guidance associated with business combinations, the assets acquired and liabilities assumed are recorded at their estimated fair value as of the acquisition date. Fair values of assets acquired and liabilities assumed are based upon available information and may involve us engaging an independent third party to perform an appraisal. Estimating fair values can be complex and subject to significant business judgment. Estimates most commonly impact property, plant and equipment and intangible assets, including goodwill. Generally, we have, if necessary, up to one year from the acquisition date to finalize our estimates of acquisition date fair values.

~~Record warm temperatures across much of the country had a significant negative affect on volumes sold and overall profitability during~~For comparative purposes, fiscal 2012. Nonetheless, we had several notable achievements during fiscal 2012, including: (i) the completion of the Inergy Propane Acquisition for approximately $1.9 billion on August 1, 2012, including the subsequent issuance of approximately 7.2 million Common Units in a secondary public offering, the net proceeds of which were used to fund a portion of the acquisition; (ii) the amendment and restatement of our revolving credit facility to a new five-year facility at lower interest rates, as well as to increase the capacity under the facility by $150.0 million; and (iii) for the sixth consecutive year, we funded all cash needs from cash on hand without the need to borrow under our Revolving Credit Facility and ended the year with $134.3 million of cash.

~~Fiscal 2012 includes 53~~2013 included 52 weeks of operations compared to 5253 weeks in fiscal 2012. In addition, the ~~prior year, and includes~~variances in year-over-year results were primarily attributable to the ~~results~~inclusion of ~~operations for~~ Inergy Propane, ~~for two months since~~acquired on August 1, 2012, as well as improvements in the ~~date of acquisition.~~operating performance in our legacy operations. Net income for fiscal ~~2012~~2013 amounted to ~~$1.9~~$78.8 million, or ~~$0.05~~$1.35 per Common Unit, compared to ~~$115.0~~$0.6 million, or ~~$3.24~~$0.02 per Common Unit, in fiscal ~~2011.~~2012. Earnings before interest, taxes, depreciation and amortization (“EBITDA”) for fiscal ~~2012~~2013 amounted to $305.2 million, compared to $86.4 million ~~compared to $178.9 million~~ for fiscal ~~2011. Adjusted~~2012.

Net income and EBITDA ~~(as defined and reconciled below) amounted to $108.5~~for fiscal 2013 included: (i) $10.6 million in ~~fiscal 2012, compared~~expenses related to ~~$179.4~~the ongoing integration of Inergy Propane; (ii) $7.0 million in ~~fiscal 2011.~~

charges related to our voluntary withdrawal from multi-employer pension plans covering certain employees acquired in the Inergy Propane Acquisition; and (iii) a loss on debt extinguishment of $2.1 million. Net income and EBITDA for fiscal 2012 ~~were negatively affected by several significant items, including:~~included: (i) $17.9 million in acquisition-related costs associated with the Inergy Propane Acquisition; (ii) a charge of $4.5 million associated with a legal ~~settlement reached during the fourth quarter of fiscal 2012 included within general and administrative expenses;~~settlement; (iii) ~~a loss on debt extinguishment of $2.2 million associated with the refinancing of our credit agreement; and (iv)~~ a $2.1 million non-cash charge from a loss on disposal of an asset in our natural gas and electricity ~~business. Net income~~business; and (iv) a loss on debt extinguishment of $2.2 million. Excluding the effects of these charges, as well as the unrealized (non-cash) mark-to-market adjustments on derivative instruments in both years, Adjusted EBITDA (as defined and reconciled below) amounted to $329.3 million for fiscal ~~2011 included a $2.0~~2013, compared to Adjusted EBITDA of $108.5 million ~~charge for severance costs associated with the realignment of our field operations.~~in fiscal 2012.

Retail propane gallons sold for fiscal ~~2012 decreased 15.1~~2013 increased 250.8 million gallons, or ~~5.1%~~88.4%, to ~~283.8~~534.6 million gallons from ~~298.9~~283.8 million gallons in fiscal ~~2011.~~2012. Sales of fuel oil and other refined fuels ~~decreased 8.7~~also increased 88.4%, to 53.7 million gallons ~~or 23.4%, to~~from 28.5 ~~million gallons compared to 37.2~~ million gallons in the prior year. ~~As reported throughout fiscal 2012,~~The increase in volumes sold was primarily attributable to the ~~most significant factor impacting volumes~~inclusion of the Inergy Propane operations for a full year, as well as increases in ~~both segments was~~our legacy operations resulting from average temperatures that were closer to normal compared to the prior year’s near record warm ~~weather experienced throughout most of the country, particularly during the critical heating months from October 2011 through March 2012.~~temperatures. According to the National Oceanic and Atmospheric Administration (“NOAA”), average temperatures (as measured by heating degree days) across all of our service territories during fiscal 2013 were 4% warmer than normal and characterized by unseasonably warm temperatures during the most critical months of the fiscal 2013 heating season, followed by colder than normal temperatures late in the heating season. In Fiscal 2012, average temperatures across our service territories were 14% warmer than ~~normal~~normal.

During fiscal 2013, we made notable progress in our integration efforts and ~~13% warmer than~~in executing our strategic financing initiatives, all of which have better positioned us operationally and financially to continue to pursue further growth opportunities. To highlight a few key accomplishments for fiscal ~~2011. The impact~~2013:

Despite the increased size of our business and ~~2.5~~the increased working capital needs, for the seventh consecutive year we continued to fund all of our working capital requirements from on hand cash without the need to borrow under our revolving credit facility and ended the fiscal year with $107.2 million ~~gallons~~ of ~~fuel oil and other refined fuels sold~~cash. Additionally, as previously reported, we took steps to further strengthen our balance sheet by redeeming $157.3 million of debt in fiscal ~~2012.~~

~~Revenues for fiscal year 2012~~2013 with a combination of ~~$1,063.5 million decreased $127.1 million, or 10.7%, compared to the prior year, primarily due to the lower volumes sold~~proceeds from a successful equity offering and lower average propane selling prices. Cost of products sold for fiscal 2012 of $599.1 million decreased $79.6 million, or 11.7%, compared to $678.7 million in the prior year as a result of lower volumes sold and lower wholesale product costs. Cost of products sold in fiscal 2012 and 2011 included a $4.6 million and $1.4 million, respectively, unrealized (non-cash) gain attributable to the mark-to-market adjustment for derivative instruments used in risk management activities which are excluded from Adjusted EBITDA in both periods. Average posted prices for propane during fiscal 2012 were 19.7% lower than the prior year, while average posted prices for fuel oil were 7.4% higher than the prior year.

Combined operating and general and administrative expenses of $357.8 million for fiscal year 2012 were $26.8 million, or 8.1%, higher than the prior year, primarily as a result of the Inergy Propane Acquisition and the legal settlement referred to above, offset to an extent by lower variable compensation attributable to lower earnings and continued savings in payroll and benefit related expenses. Depreciation and amortization expense of $45.8 million increased $10.2 million, or 28.7%, primarily due to the impact of the Inergy Propane Acquisition. Net interest expense of $38.6 million for fiscal 2012 increased $11.2 million, or 40.9%, compared to the prior year as a result of higher debt levels associated with the financing for the Inergy Propane Acquisition.cash on hand.

As we look ahead to fiscal ~~2013,~~2014, our anticipated cash requirements ~~will increase compared to historical trends as a result of the Inergy Propane Acquisition, and~~ include: (i) maintenance and growth capital expenditures of approximately ~~$51.0~~$30.0 million; (ii) approximately ~~$100.0~~$88.1 million of interest and income tax payments; and (iii) approximately ~~$198.3~~$211.1 million of distributions to Unitholders, assuming distributions at ~~an annualized rate of $3.41 per Common Unit paid in respect of~~ the ~~fourth quarter of fiscal 2012, and at an~~current annualized rate of $3.50 per Common Unit beginning with the distribution to be paid in respect of the first quarter of fiscal 2013. The expected increase in the annualized distribution rate to $3.50 per Common Unit was previously announced by us on April 26, 2012.Unit. Based on our current cash position, availability under the Revolving Credit Facility (unused borrowing capacity of ~~$253.2~~$253.3 million at September ~~29, 2012)~~28, 2013) and expected cash flow from operating activities, we expect to have sufficient funds to meet our current and future obligations.


(Dollars in thousands)	Fiscal 2012		Fiscal 2011		Increase/ (Decrease)			Percent Increase/ (Decrease)										Percent
											Fiscal		Fiscal		Increase/			Increase/
											2012		2011		(Decrease)			(Decrease)
Revenues
Propane	$	843,648	$	929,492	$	(85,844	)		(9.2	%)	$	843,648	$	929,492	$	(85,844	)		(9.2	%)
Fuel oil and refined fuels		114,288		139,572		(25,284	)		(18.1	%)		114,288		139,572		(25,284	)		(18.1	%)
Natural gas and electricity		67,419		84,721		(17,302	)		(20.4	%)		67,419		84,721		(17,302	)		(20.4	%)
All other		38,103		36,767		1,336			3.6	%		38,103		36,767		1,336			3.6	%

Total revenues	$	1,063,458	$	1,190,552	$	(127,094	)		(10.7	%)	$	1,063,458	$	1,190,552	$	(127,094	)		(10.7	%)

Total revenues decreased $127.1 million, or 10.7%, to $1,063.5 million in fiscal 2012 compared to $1,190.6 million for fiscal 2011, primarily due to lower volumes sold and, to a much lesser extent, lower average propane selling prices. From a weather perspective, average temperatures as measured in heating degree days, as reported by the NOAA, in our service territories during fiscal 2012 were 14% and 13% warmer than normal and the prior year, respectively. Record warm temperatures were experienced throughout much of the northeast and significantly warmer than normal temperatures were reported throughout the east coast. Average temperatures in the northeast and southeast regions for fiscal 2012 were 18% and 26%, respectively, warmer than the prior year.

Revenues from the distribution of propane and related activities of $843.6 million for fiscal 2012 decreased $85.9 million, or 9.2%, compared to $929.5 million for the prior year, primarily due to lower volumes sold and lower average propane selling prices. Retail propane gallons sold in fiscal 2012 decreased 15.1 million gallons, or 5.1%, to 283.8 million gallons from 298.9 million gallons in the prior year. The volume decline was more pronounced within our residential customer base as the impact of weather has a greater effect on our residential customers’ propane consumption, which, during the winter, is primarily for space heating. The impact of record warm temperatures on volumes sold was offset to an extent by the addition of propane volumes sold from Inergy Propane since August 1, 2012, which contributed 27.0 million gallons of propane gallons sold in fiscal 2012. Average propane selling prices for fiscal 2012 decreased 5.0% compared to the prior year due to lower wholesale product costs. Included within the propane segment are revenues from other propane activities of $74.2 million for fiscal 2012, which decreased $2.3 million compared to the prior year.

Revenues from the distribution of fuel oil and refined fuels of $114.3 million for fiscal 2012 decreased $25.3 million, or 18.1%, from $139.6 million in the prior year, primarily due to lower volumes sold, partially offset by higher average selling prices associated with higher wholesale product costs. Fuel oil and refined fuels gallons sold in fiscal 2012 decreased 8.7 million gallons, or 23.5%, to 28.5 million gallons from 37.2 million gallons in the prior year. Average selling prices in our fuel oil and refined fuels segment for fiscal 2012 increased 6.6% compared to the prior year due to higher wholesale product costs.

Revenues in our natural gas and electricity segment decreased $17.3 million, or 20.4%, to $67.4 million in fiscal 2012 compared to $84.7 million in the prior year as a result of lower natural gas and electricity volumes sold, which was primarily attributable to the record warm weather in the northeast, discussed above.

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

Average posted prices for propane for fiscal 2012 were 19.7% lower than the prior year, and average fuel oil prices for fiscal 2012 were 7.4% higher than the prior year. Total cost of products sold decreased $79.7 million, or 11.7%, to $599.1 million in fiscal 2012, compared to $678.7 million in the prior year due to lower volumes sold and lower propane average product costs, partially offset by higher fuel oil average product costs. The net change in the fair value of derivative instruments resulted in unrealized (non-cash) gains reported in cost of product sold of $4.6 million and $1.4 million during fiscal 2012 and 2011, respectively, resulting in a decrease of $3.2 million in cost of products sold in fiscal 2012 compared to the prior year ($4.8 million decrease and $1.6 million increase in cost of products sold reported in the propane segment and fuel oil and refined fuels segment, respectively).

Cost of products sold associated with the distribution of propane and related activities of $448.1 million for fiscal 2012 decreased $58.4 million, or 11.5%, compared to the prior year. Lower average propane costs and lower propane volumes sold resulted in a decrease in cost of products sold of $30.5 million and $23.7 million, respectively, in fiscal 2012 compared to the prior year. Cost of products sold from other propane activities increased $0.6 million in fiscal 2012 compared to the prior year.

Cost of products sold associated with our fuel oil and refined fuels segment of $91.2 million for fiscal 2012 decreased $9.7 million, or 9.6%, compared to the prior year. Lower fuel oil and refined fuels volumes sold resulted in a decrease of $22.6 million in cost of products sold during fiscal 2012 compared to the prior year. The impact of the decrease in volumes sold was partially offset by higher average fuel oil and refined fuels costs, which resulted in an $11.3 million increase in cost of products sold during fiscal 2012 compared to the prior year.

Cost of products sold in our natural gas and electricity segment of $46.9 million for fiscal 2012 decreased $14.6 million, or 23.7%, compared to the prior year, primarily due to lower natural gas and electricity volumes sold.

Cost of products sold as a percent of revenues of 56.3% for fiscal 2012 decreased 0.7 percentage points, compared to 57.0% for the prior year. The decrease in cost of products sold as a percentage of revenues was primarily attributable to wholesale propane product costs declining at a slightly faster pace than the decline in average propane selling prices.

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 $298.7 million for fiscal 2012 increased ~~$19.4~~$17.4 million, or ~~7.0%~~6.2%, compared to ~~$279.3~~$281.3 million in the prior year as a result of the Inergy Propane Acquisition, offset to an extent by lower payroll and benefit related expenses resulting from a lower headcount and other operating efficiencies, as well as lower bad debt expense and insurance costs. During fiscal 2011 we recorded severance charges of $2.0 million related to the realignment of our operating footprint.

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

General and administrative expenses of $59.0 million for fiscal 2012 increased approximately $7.4 million compared to $51.6 million in the prior year. General and administrative expenses for fiscal 2012 included a $4.5 million charge associated with a legal settlement (see Item 3 and Note 12 included within the Notes to the Consolidated Financial Statements section elsewhere in this Annual Report for additional discussion), and a $2.1 million non-cash charge from a loss on disposal of an asset used in our natural gas and electricity business. General and administrative expenses for fiscal 2011 included a $2.5 million gain on sale of an asset. Excluding the impact of these items, general and administrative expenses decreased $1.8 million primarily due to lower variable compensation associated with lower earnings, offset to an extent by the addition of Inergy Propane.

During fiscal 2012 we recorded acquisition-related costs of $17.9 million related to the Inergy Propane Acquisition. These costs were primarily attributable to investment banker, legal, accounting and other consulting fees.

~~During fiscal 2011 we recorded severance charges of $2.0 million related to the realignment of our regional operating footprint.~~


(Dollars in thousands)	Fiscal 2012			Fiscal 2011			Increase		Percent Increase
												Fiscal			Fiscal					Percent
												2012			2011			Increase		Increase
Depreciation and amortization	$	45,790		$	35,628		$	10,162		28.5	%	$	47,034		$	35,628		$	11,406		32.0	%
As a percent of total revenues		4.3	%		3.0	%							4.4	%		3.0	%

Depreciation and amortization expense of ~~$45.8~~$47.0 million in fiscal 2012 increased ~~$10.2~~$11.4 million, or ~~28.5%~~32.0%, compared to $35.6 million in the prior year, primarily as a result of tangible and intangible long-lived assets acquired in the Inergy Propane Acquisition.


(Dollars in thousands)	Fiscal 2012			Fiscal 2011			Increase		Percent Increase
												Fiscal			Fiscal					Percent
												2012			2011			Increase		Increase
Interest expense, net	$	38,633		$	27,378		$	11,255		41.1	%	$	38,633		$	27,378		$	11,255		41.1	%
As a percent of total revenues		3.6	%		2.3	%							3.6	%		2.3	%

Net interest expense of $38.6 million for fiscal 2012 increased $11.2 million compared to $27.4 million in the prior year, primarily due to higher debt levels associated with the financing for the Inergy Propane Acquisition. See Liquidity and Capital Resources below for additional discussion on the debt issued in connection with the Inergy Propane Acquisition.

In connection with the execution of the amendment of our credit agreement on January 5, 2012, we recognized a non-cash charge of $0.5 million to write-off a portion of unamortized debt origination costs associated with the credit agreement during the first quarter of fiscal 2012. In addition, in connection with the repayment, on August 14, 2012, of borrowings under our 364-Day Facility which was used as short-term financing to fund a portion of the Inergy Propane Acquisition, we recognized a non-cash charge of $1.7 million to write off unamortized debt origination costs associated with the 364-Day Facility during the fourth quarter of fiscal 2012. See Liquidity and Capital Resources below for additional discussion on the amendment to the credit agreement.

We reported net income of ~~$1.9~~$0.6 million, or ~~$0.05~~$0.02 per Common Unit in fiscal 2012 compared to net income of $115.0 million, or $3.24 per Common Unit in the prior year. Adjusted EBITDA amounted to $108.5 million in fiscal 2012, compared to $179.4 million in fiscal 2011.

Net income and EBITDA for fiscal 2012 were negatively affected by several significant items, including: (i) $17.9 million in acquisition-related costs associated with the Inergy Propane Acquisition; (ii) a charge of $4.5 million associated with a legal settlement reached during the fourth quarter of fiscal 2012 included within general and administrative expenses; (iii) a loss on debt extinguishment of $2.2 million; and (iv) a $2.1 million non-cash charge from a loss on disposal of an asset in our natural gas and electricity business. Net income and EBITDA for fiscal 2011 included a $2.0 million charge for severance costs associated with the realignment of our field operations.

Adjusted EBITDA represents EBITDA excluding the unrealized net gain or loss from mark-to-market activity for derivative instruments and other certain items as provided in the table below. 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. EBITDA and Adjusted EBITDA are not recognized terms under US GAAP and should not be considered as an alternative to net income or net cash provided by operating activities determined in accordance with US GAAP. Because EBITDA and Adjusted EBITDA as determined by us excludes some, but not all, items that affect net income, they may not be comparable to EBITDA and Adjusted EBITDA or similarly titled measures used by other companies.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

   Year Ended
   September 24, September 25,
(Dollars in thousands)    2011 2010
Net income
   $ 114,966    $ 115,316
Add:

Provision for income taxes
   884    1,182
Interest expense, net
   27,378    27,397
Depreciation and amortization
   35,628    30,834


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


Adjusted EBITDA
   179,425    192,420
Add (subtract):

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


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

Operating Activities. Net cash provided by operating activities for fiscal ~~2012~~2013 amounted to ~~$111.0~~$214.3 million, ~~a decrease~~an increase of ~~$21.8~~$103.3 million compared to the prior year. The ~~decrease~~increase was primarily attributable to ~~a $97.6 million decrease~~an increase in earnings, after adjusting for non-cash items in both ~~periods, offset~~periods. In addition, average posted prices for propane during fiscal 2013 decreased 19.2% compared to the prior year, which resulted in a substantial reduction in working capital requirements year-over-year. Also, cash flows from operating activities for fiscal 2013 benefited to an extent by ~~a $75.8 million year-over-year increase in cash provided by reductions in~~the realization of working capital ~~primarily due~~acquired in the Inergy Propane Acquisition.

Investing Activities. Net cash used in investing activities of $14.7 million for fiscal 2013 consisted of capital expenditures of $27.8 million (including $8.3 million for maintenance expenditures and $19.5 million to support the growth of operations), partially offset by the net proceeds of $7.3 million from the sale of property, plant and equipment, and net proceeds of $5.8 million from Inergy as a ~~reduction in accounts receivable and inventories due~~result of a purchase price adjustment attributable to the ~~decline in sales volumes, as well as the year-over-year decline in wholesale propane product costs.~~

~~Investing Activities.~~working capital of Inergy Propane. Net cash used in investing activities of $239.8 million for fiscal 2012 consisted of ~~the cash portion of the consideration for the Inergy Propane Acquisition as well as~~ capital expenditures of $17.5 million (including $9.3 million for maintenance expenditures and $8.2 million to support the growth of operations), and business acquisitions of $223.7 million, partially offset by the net proceeds from the sale of property, plant and equipment of $1.4 million.

Financing Activities. Net cash used in ~~investing~~financing activities ~~of $19.5 million~~ for fiscal ~~2011 consisted~~2013 of ~~capital expenditures~~$226.7 million reflects the quarterly distribution to Common Unitholders at a rate of ~~$22.3~~$0.8525 per Common Unit paid in respect of the fourth quarter of fiscal 2012 and at a rate of $0.8750 per Common Unit paid in respect of the first, second and third quarters of fiscal 2013. In addition, net cash used in financing activities for fiscal 2013 includes proceeds of $143.4 million ~~(including $10.2 million for maintenance expenditures and $12.1 million to support~~from the ~~growth~~issuance of ~~operations) and business acquisitions~~3,105,000 of ~~$3.2 million, partially offset by the~~our Common Units in May 2013. The net proceeds from the ~~sale~~equity offering, along with cash on hand, were used to redeem $157.3 million of ~~property, plant and equipment of $6.0 million.~~

~~Financing Activities.~~Net cash provided by financing activities for fiscal 2012 of $113.5 million ~~essentially~~ reflects the net proceeds of $259.8 million from the issuance of 7.2 million Common Units in a public offering, net of $25.2 million in debt origination costs, consisting of $10.3 million in debt origination costs associated with the amendments to our credit agreement and $14.9 million in debt origination costs associated with the issuance of new senior notes in connection with the Inergy Propane Acquisition, and $121.1 million in quarterly distributions to Unitholders at a rate of $0.8525 per Common Unit paid in respect of the fourth quarter of fiscal 2011 and the first, second and third quarters of fiscal 2012. With the execution of the amendment of our credit agreement on January 5, 2012, we rolled the $100.0 million then-outstanding under the revolving credit facility of the previous credit agreement into the Revolving Credit Facility (defined below) of the Amended Credit Agreement (defined below). This resulted in the repayment of the $100.0 million then-outstanding under the Revolving Credit Facility of the previous credit agreement with proceeds from borrowings under the Revolving Credit Facility of the amended credit agreement.

~~Net cash used in financing activities~~See Summary of Long-Term Debt Obligations and Revolving Credit Lines below for fiscal 2011 of $120.6 million reflects quarterly distributions to Unitholders at a rate of $0.8525 per Common Unit paid in respect of the fourth quarter of fiscal 2011 and the first, second and third quarters of fiscal 2012.additional discussion.

On ~~August 14, 2012,~~May 17, 2013, we sold ~~6,300,000~~2,700,000 Common Units in a public offering at a price of ~~$37.61~~$48.16 per Common Unit realizing proceeds of ~~$225.7~~$124.7 million, net of underwriting commissions and other offering expenses. ~~Also on August 14, 2012, we used the net proceeds from the offering to repay our borrowings of $225.0 million on August 1, 2012 under our 364-Day Facility.~~ On ~~August 20, 2012,~~May 22, 2013, following the underwriters’ exercise of their over-allotment option, we sold an additional ~~945,000~~405,000 Common Units at ~~$37.61~~$48.16 per Common Unit, generating additional ~~net~~ proceeds of ~~$34.1~~$18.7 million, net of underwriting commissions. The net proceeds from the offering, including the net proceeds from the underwriters’ exercise of their over-allotment option, were used to redeem $133.4 million of our 2021 senior notes in August 2013, including prepayment premiums and other expenses.

As of September ~~29, 2012,~~28, 2013, our long-term debt consisted of $496.6 million in aggregate principal amount of ~~unregistered~~ 7.5% senior notes due October 1, 2018, $250.0 million in aggregate principal amount of 7.375% senior notes due March 15, 2020, ~~$503.4~~$346.2 million in aggregate principal amount of ~~unregistered~~ 7.375% senior notes due August 1, 2021 and $100.0 million under our senior secured Revolving Credit Facility.

On August 1, 2012, the Partnership and its 100%-owned subsidiary, Suburban Energy Finance Corp., issued $496.6 million in aggregate principal amount of unregistered 7.5% senior notes due October 1, 2018 (the “2018 Senior Notes”) and $503.4 million in aggregate principal amount of unregistered 7.375% senior notes due August 1, 2021 (the “2021 Senior Notes”) in a private placement in connection with the Inergy Propane Acquisition. Based on market rates for similar issues, the 2018 Senior Notes and 2021 Senior Notes were valued at 106.875% and 108.125%, respectively, of the principal amount, on the ~~date of acquisition~~Acquisition Date as they were issued in exchange for Inergy’s outstanding notes, not for cash. The 2018 Senior Notes require semi-annual interest payments in April and October, and the 2021 Senior Notes require semi-annual interest payments in February and August.

The 2018 Senior Notes are redeemable, at our option, in whole or in part, at any time after October 1, 2014, in each case at the redemption prices described in the table below, together with any accrued and unpaid interest to the date of the redemption.

The 2021 Senior Notes are redeemable, at our option, in whole or in part, at any time after August 1, 2016, in each case at the redemption prices described in the table below, together with any accrued and unpaid interest to date of the redemption.


Year	Percentage
2016		103.688	%
2017		102.459	%
2018		101.229	%
2019 and thereafter		100.000	%

On ~~November 13,~~December 19, 2012, we ~~offered~~completed an offer to exchange ~~its~~our existing unregistered 7.5% senior notes due 2018 and 7.375% senior notes due 2021 ~~(collectively, the~~(the “Old Notes”) for an equal principal amount of 7.5% senior notes due 2018 and 7.375% senior notes due 2021 ~~(collectively, the~~(the “Exchange Notes”), respectively, that have been registered under the Securities Act of 1933, as amended. The terms of the Exchange Notes are identical in all material respects (including principal, ~~amount,~~ interest rate, maturity and redemption rights) to the Old Notes for which they ~~may be~~were exchanged, except that the Exchange Notes generally will not be subject to transfer restrictions. ~~The exchange offer expires~~

On August 2, 2013, we repurchased, pursuant to optional redemption, $133.4 million of our 2021 Senior Notes using net proceeds from our May 2013 public offering and net proceeds from the underwriters’ exercise of their over-allotment option to purchase additional Common Units. In addition, on ~~December 13, 2012, unless otherwise extended.~~August 6, 2013, we repurchased $23.9 million of our 2021 Senior Notes in a private transaction using cash on hand. In connection with these repurchases, which totaled $157.3 million in aggregate principal amount, we recognized a loss on the extinguishment of debt of $2.1 million consisting of $11.7 million for the repurchase premium and related fees, as well as the write-off of $2.1 million and ($11.7) million in unamortized debt origination costs and unamortized premium, respectively.

On March 23, 2010, the Partnership and its 100%-owned subsidiary, Suburban Energy Finance Corp., completed a public offering of $250.0 million in aggregate principal amount of 7.375% senior notes due March 15, 2020 (the “2020 Senior Notes”). The 2020 Senior Notes were issued at 99.136% of the principal ~~amount. The net proceeds from the issuance, along with cash on hand, were used to repurchase the 6.875% senior notes due in 2013 (the “2013 Senior Notes”) on March 23, 2010 through a redemption~~amount and tender offer. In connection with the repurchase of the 2013 Senior Notes, we recognized a loss on the extinguishment of debt of $9.5 million in fiscal 2010, consisting of $7.2 million for the repurchase premium and related fees, as well as the write-off of $2.3 million in unamortized debt origination costs and unamortized discount. The 2020 Senior Notes require semi-annual interest payments in March and September.

The 2020 Senior Notes are redeemable, at our option, in whole or in part, at any time after March 15, 2015, in each case at the redemption prices described in the table below, together with any accrued and unpaid interest to the date of the redemption.

Our obligations under the 2018 Senior Notes, 2020 Senior Notes and 2021 Senior Notes (collectively, the “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 Senior Notes are structurally subordinated to, which means they rank effectively behind, any debt and other liabilities of the Operating Partnership. The 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 a change of control, as defined in the indenture, occurs and is followed by a rating decline (a decrease in the rating of the notes by either Moody’s Investors Service or Standard and Poor’s Rating Group by one ofor more gradations) within 90 days of the consummation of the change of control.

Our Operating Partnership has a credit agreement, as amended on January 5, 2012 and August 1, 2012 (the “Amended Credit Agreement”) that provides for a five-year $400.0 million revolving credit facility (the “Revolving Credit Facility”), of which $100.0 million was outstanding as of September ~~29, 2012~~28, 2013 and September ~~24, 2011.~~29, 2012. Borrowings under the Revolving Credit Facility may be used for general corporate purposes, including working capital, capital expenditures and acquisitions. Our 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.

The amendment to the credit agreement on January 5, 2012 amended the previous credit agreement to, among other things, extend the maturity date from June 25, 2013 to January 5, 2017, reduce the borrowing rate and commitment fees, and amend certain affirmative and negative covenants. ~~On the date~~As of ~~the~~ January 5, 2012, ~~amendment,~~ our Operating Partnership had borrowings of $100.0 million outstanding under the revolving credit facility of the previous credit agreement, and rolled those borrowings into the Revolving Credit Facility of the Amended Credit Agreement. ~~In addition,~~Also, at ~~the~~such time, ~~the January 5, 2012 amendment was entered into,~~ our Operating Partnership had letters of credit issued under the revolving credit facility of the previous credit agreement primarily in support of retention levels under its self-insurance programs, all of which have been rolled into the Revolving Credit Facility of the Amended Credit Agreement.

On April 25, 2012, we received consents from the requisite lenders under the Amended Credit Agreement to enable us to incur additional indebtedness, make amendments to the Amended Credit Agreement to adjust certain covenants, and otherwise perform our obligations as contemplated by the Inergy Propane Acquisition. On August 1, 2012, our Operating Partnership executed an amendment to the Amended Credit Agreement to, among other things, provide for (i) a $250.0 million senior secured 364-Day Facility and (ii) an increase in our revolving credit facility under the Amended Credit Agreement from $250.0 million to $400.0 million. On the Acquisition Date, our Operating Partnership drew $225.0 million on the 364-Day Facility, which was used to fund a portion of the Inergy Propane Acquisition, including costs and expenses related to the acquisition. We repaid the $225.0 million of borrowings under the 364-Day Facility on August 14, 2012 with the net proceeds from the public issuance of Common Units on August 14, 2012.

The amendment to the Amended Credit Agreement on August 1, 2012 also amended certain restrictive and affirmative covenants applicable to our Operating Partnership and to us, as well as certain financial covenants, including (a) requiring our consolidated interest coverage ratio, as defined in the amendment, to be not less than 2.0 to 1.0 as of the end of any fiscal quarter; (b) prohibiting the total consolidated leverage ratio, as defined in the amendment, of the Partnership from being greater than 7.0 to 1.0 as of the end of any fiscal quarter. The minimum consolidated interest coverage ratio increases over time, and commencing with the ~~second~~third quarter of fiscal ~~2015,~~2014, such minimum ratio will be 2.5 to 1.0. The maximum consolidated leverage ratio decreases over time, ~~and commencing~~as well as upon the occurrence of certain events (such as the issuance of Common Units where the net proceeds from the issuance exceed certain thresholds). Commencing with the ~~first~~second quarter of fiscal ~~2015,~~2013, such maximum ratio will be 4.75 to ~~1.0.~~1.0 (or 5.0 to 1.0 during an acquisition period as defined in the amendment) as a result of the issuance of Common Units in August 2012. As of September ~~29, 2012~~28, 2013 the minimum consolidated interest coverage ratio and maximum consolidated leverage ratio was ~~2.0~~2.25 to 1.0 and ~~5.75~~4.75 to 1.0, respectively.

We act as a guarantor with respect to the obligations of our Operating Partnership under the Amended Credit Agreement pursuant to the terms and conditions set forth therein. The obligations under the Amended 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.

Borrowings under the Revolving Credit Facility of the Amended Credit Agreement 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 plus¹⁄₂ of 1%, the agent bank’s prime rate, or LIBOR plus 1%, plus in each case the applicable margin. The applicable margin is dependent upon the Partnership’s ratio of Consolidated Total Debt to Consolidated EBITDA, as defined in the Revolving Credit Facility. As of September 28, 2013, the interest rate for the Revolving Credit Facility was approximately 2.8%. The interest rate and the applicable margin will be reset at the end of each calendar quarter.

In connection with the previous revolving credit facility, ~~our~~the Operating Partnership entered into an interest rate swap agreement with a notional amount of $100.0 million, ~~and~~ an effective date of March 31, 2010 and termination date of June 25, 2013. Under the interest rate swap agreement, ~~our~~the Operating Partnership ~~will pay~~paid 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 our~~paid to the Operating Partnership a floating rate, namely LIBOR, on the same notional principal amount. The interest rate swap ~~has been~~was designated as a cash flow hedge. In connection with the Amended Credit Agreement, our Operating Partnership entered into a forward starting interest rate swap agreement with a notional amount of $100.0 million, and effective date of June 25, 2013 ~~effective date, which is commensurate with the maturity of the existing interest rate swap agreement,~~ and a ~~maturity~~termination date of January 5, 2017. Under this forward starting interest rate swap agreement, our Operating Partnership will pay a fixed interest rate of 1.63% to the issuing lender on the notional principal amount outstanding, and the issuing lender will pay our Operating Partnership a floating rate, namely LIBOR, on the same notional principal amount. The forward starting interest rate swap has been designated as a cash flow hedge.

As of September ~~29, 2012,~~28, 2013, our Operating Partnership had standby letters of credit issued under the Revolving Credit Facility in the aggregate amount of ~~$46.8~~$46.7 million which expire periodically through ~~September 1, 2013.~~April 3, 2014. Therefore, as of September ~~29, 2012~~28, 2013 we had available borrowing capacity of ~~$253.2~~$253.3 million under the Revolving Credit Facility.

The Amended Credit Agreement and the Senior Notes both contain various restrictive and affirmative covenants applicable to the Operating Partnership and the Partnership, respectively, including (i) restrictions on the incurrence of additional indebtedness, and (ii) restrictions on certain liens, investments, guarantees, loans, advances, payments, mergers, consolidations, distributions, sales of assets and other transactions. Under the Amended Credit Agreement and the indentures governing the Senior Notes, the Operating Partnership isand the Partnership 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 with respect to the ~~Partnership’s~~indentures governing the Senior Notes, our consolidated fixed charge coverage ratio, as defined, is greater than 1.75 to 1. We and our Operating Partnership were in compliance with all covenants and terms of the Senior Notes and the Amended Credit Agreement as of September ~~29, 2012.~~28, 2013.

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. During fiscal 2013, we recognized charges of $2.1 million to write-off unamortized debt origination costs associated with the repurchase of our 2021 Senior Notes. During fiscal 2012, we capitalized $14.9 million and $10.3 million for costs incurred in connection with issuance of new senior notes and the amendments to our Amended Credit Agreement, respectively. We recognized charges of $2.2 million to write-off unamortized debt origination costs associated with the amendment to our Amended Credit Agreement on January 5, 2012 and the repayment of borrowings under our 364-Day Facility. Other assets at September ~~29, 2012~~28, 2013 and September ~~24, 2011~~29, 2012 include debt origination costs with a net carrying amount of ~~$28.1~~$21.3 million and ~~$7.2~~$28.1 million, respectively.

The aggregate amounts of long-term debt maturities subsequent to September ~~29, 2012~~28, 2013 are as follows: fiscal ~~2013~~2014 through fiscal 2016: $-0-; fiscal 2017: $100.0 million; fiscal 2018: $496.6 million; and thereafter: ~~$1.25 billion.~~$596.2 million.

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 25, 2012, we announced a quarterly distribution of $0.8525 per Common Unit, or $3.41 on an annualized basis, in respect of the fourth quarter of fiscal 2012 payable on November 13, 2012 to holders of record on November 6, 2012. On April 26, 2012,24, 2013, we announced that our Board of Supervisors ~~approved an increase in~~had declared a quarterly distribution of $0.8750 per Common Unit for the ~~annualized~~three months ended September 28, 2013. This quarterly distribution rate equates to an annualized rate of $3.50 per Common Unit, which represents ~~an increase~~a growth rate of ~~$0.09~~2.6% when compared to the annualized rate of $3.41 per Common Unit ~~or 2.6%, compared to our current annualized distribution rate.~~as of the end of fiscal year 2012. The distribution ~~at the increased rate will be effective for the quarterly distribution~~was paid ~~in respect~~on November 12, 2013 to Common Unitholders of ~~the first quarter~~record as of ~~fiscal 2013 ending December 29, 2012.~~November 5, 2013.

We have a noncontributory defined benefit pension plan which was originally designed to cover all eligible employees of the Partnership who met certain requirements as to age and length of service. Effective January 1, 1998, we amended the 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. 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 2013, 2012 ~~2011~~ or ~~2010.~~2011. As of September ~~29, 2012~~28, 2013 and September ~~24, 2011~~29, 2012 the plan’s projected benefit obligation exceeded the fair value of plan assets by ~~$32.0~~$27.9 million and ~~$26.2~~$32.0 million, respectively. As a result, the net liability recognized in the consolidated financial statements for the defined benefit pension plan ~~increased~~decreased by ~~$5.8~~$4.1 million during fiscal ~~2012,~~2013, which was primarily attributable to ~~an increase~~a decrease in the present value of the benefit obligation due to a general ~~decrease~~increase in market interest rates, partially offset by ~~the growth~~a decline in the value of plan assets ~~from~~as a result of investment ~~earnings~~losses during fiscal ~~2012.~~2013. As discussed below, plan assets are largely invested in fixed income securities and, as such, an increase in market interest rates will generally result in negative returns on plan assets.

Our investment policies and strategies, as set forth in the Investment Management Policy and Guidelines, are monitored by a Benefits Committee comprised of five members of management. The Benefits Committee employs a liability driven investment strategy, which seeks to increase the correlation of the plan’s assets and liabilities to reduce the volatility of the plan’s funded status. The execution of this strategy has resulted in an asset allocation that is largely comprised of fixed income securities. A liability driven investment strategy is intended to reduce investment risk and, over the long-term, generate returns on plan assets that largely fund the annual interest on the accumulated benefit obligation. However, as we experienced in fiscal 2012, ~~and fiscal 2011,~~ significant declines in interest rates relevant to our benefit obligations, or poor performance in the broader capital markets in which our plan assets are invested, could have an adverse impact on the funded status of the defined benefit pension plan. For purposes of measuring the projected benefit obligation as of September ~~29, 2012~~28, 2013 and September ~~24, 2011,~~29, 2012, we used a discount rate of ~~3.5%~~4.375% and ~~4.375%~~3.5%, respectively, reflecting current market rates for debt obligations of a similar duration to our pension obligations.

During fiscal 2013, fiscal 2012 and fiscal 2011, the amount of the pension benefit obligation settled through lump sum payments did not exceed the settlement threshold (combined service and interest costs of net periodic pension cost); therefore, a settlement charge was not required to be recognized in either of those fiscal years. During fiscal 2010, lump sum pension settlement payments to either terminated or retired individuals amounted to $7.9 million, which exceeded the settlement threshold of $7.5 million for fiscal 2010, and as a result, the Partnership was required to recognize a non-cash settlement charge of $2.8 million during fiscal 2010. The non-cash charge was required to accelerate recognition of a portion of cumulative unamortized losses in the defined benefit pension plan. 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.

The following table summarizes payments due under our known contractual obligations as of September ~~29, 2012:~~28, 2013:


																								Fiscal
(Dollars in thousands)	Fiscal 2013			Fiscal 2014		Fiscal 2015		Fiscal 2016		Fiscal 2017		Fiscal 2018 and thereafter		Fiscal		Fiscal		Fiscal		Fiscal		Fiscal		2019 and
														2014		2015		2016		2017		2018		thereafter
Long-term debt obligations	$	—		$	—	$	—	$	—	$	100,000	$	1,250,000	$	—	$	—	$	—	$	100,000	$	496,557	$	596,180
Interest payments		98,696			97,954		97,954		97,954		94,166		225,663		86,356		86,356		86,356		82,568		81,210		122,869
Operating lease obligations (a)		28,254			23,848		17,396		10,188		6,012		7,306		27,238		20,488		12,770		7,894		5,208		5,947
Self-insurance obligations (b)		12,147	��		11,477		8,367		4,872		3,126		14,561		14,552		11,910		9,021		5,300		3,284		14,085
Other contractual obligations (c)		8,616			7,735		6,409		3,926		2,532		18,873		5,087		5,702		5,032		2,465		2,204		17,450

Total	$	147,713		$	141,014	$	130,126	$	116,940	$	205,836	$	1,516,403	$	133,233	$	124,456	$	113,179	$	198,227	$	588,463	$	756,531

(b)

The timing of when payments are due for our self-insurance obligations is based on estimates that may differ from when actual payments are made. In addition, the payments do not reflect amounts to be recovered from our insurance providers, which amount to ~~$4.2~~$4.3 million, $3.5 million, ~~$2.6~~$2.8 million, ~~$1.4~~$1.5 million, $1.0 million and ~~$4.9~~$5.3 million for each of the next five fiscal years and thereafter, respectively, and are included in other assets on the consolidated balance sheet.

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

Additionally, we have standby letters of credit in the aggregate amount of ~~$46.8~~$46.7 million, in support of retention levels under our casualty insurance programs and certain lease obligations, which expire periodically through ~~September 1, 2013.~~April 15, 2014.

We lease certain property, plant and equipment for various periods under noncancelable operating leases, including ~~39%~~40% of our vehicle fleet, approximately 30% of our customer service centers and portions of our information systems equipment. Rental expense under operating leases was $33.0 million, $23.6 million ~~$18.9 million~~ and ~~$17.6~~$18.9 million for fiscal 2013, 2012 ~~2011~~ and ~~2010,~~2011, respectively. Future minimum rental commitments under noncancelable operating lease agreements as of September ~~29, 2012~~28, 2013 are presented in the table above.

Certain of our operating leases, primarily those for transportation equipment with remaining lease periods scheduled to expire periodically through fiscal ~~2019,~~2020, 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 ~~$18.0~~$16.3 million. The fair value of residual value guarantees for outstanding operating leases was de minimis as of September ~~29, 2012~~28, 2013 and September ~~24, 2011.~~29, 2012.

In ~~June~~December 2011, the Financial Accounting Standards Board (“FASB”) issued an accounting standards update (“ASU”) regarding disclosures about offsetting assets and liabilities (“ASU 2011-11”). The new guidance requires an entity to disclose information about offsetting and related arrangements to enable users of financial statements to understand the effect of those arrangements on its financial position. The amendments, further clarified with ASU 2013-01, will enhance disclosures by requiring improved information about financial instruments and derivative instruments that are either offset in accordance with other US GAAP or subject to an enforceable master netting arrangement or similar agreement, irrespective of whether or not they are offset in the balance sheet. The new guidance is effective for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods, which will be our first quarter of its 2014 fiscal year. We are currently evaluating the impact of the new guidance on our future disclosures.

In February 2013, the FASB issued an ~~accounting standard update~~ASU to ~~provide guidance on increasing~~establish the ~~prominence of items reported in other comprehensive income. This update eliminates~~effective date for the ~~option~~requirement to present components of reclassifications out of accumulated other comprehensive income ~~as part~~either parenthetically on the face of the statement of partners’ capital and requires that the total of comprehensive income, the components of net income and the components of other comprehensive income be presented either in a single continuous statement of comprehensive incomefinancial statements or in ~~two separate but consecutive statements. Early adoption of this updated~~the notes to the financial statements (“ASU 2013-02”). The guidance is ~~permitted, and it becomes~~ effective ~~retrospectively~~prospectively for ~~fiscal years~~annual periods beginning after December 15, ~~2011,~~2012, and interim periods within those annual periods, which will be the first quarter of our ~~2013~~2014 fiscal year. ~~This update does~~The adoption of ASU 2013-02 will not change the items that must be reported in other comprehensive ~~income but will require the Partnership to change its historical practice of showing comprehensive income within the Statement of Partners’ Capital.~~income.

In September 2011, the FASB issued an accounting standards update allowing companies to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If, as a result of the qualitative assessment, it is more likely than not that the fair value of a reporting unit is less than its carrying amount, a more detailed two-step goodwill impairment test would be performed to identify a potential goodwill impairment and measure the amount of loss to be recognized, if any. The standard is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011, which will be the Partnership’s 2013 fiscal year. Early adoption is permitted. The adoption of this standard is not expected to impact the Partnership’s financial position, results of operations or cash flows.

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

Product cost changes can occur rapidly over a short period of time and can impact profitability. We attempt to reduce commodity price risk by pricing product on a short-term basis. The level of priced, physical product maintained in storage facilities and at our customer service centers for immediate sale to our customers will vary depending on several factors, including, but not limited to, price, supply and demand dynamics for a given time of the year. Typically, our on hand priced position does not exceed more than four to eight weeks of our supply needs, depending on the time of the year. In the course of normal operations, we routinely enter into contracts such as forward priced physical contracts for the purchase or sale of propane and fuel oil that, under accounting rules for derivative instruments and hedging activities, qualify for and are designated as normal purchase or normal sale contracts. Such contracts are exempted from fair value accounting and are accounted for at the time product is purchased or sold under the related contract.

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

Futures are traded with brokers of the NYMEX and require daily cash settlements in margin accounts. Forward contracts are generally settled at the expiration of the contract term by physical delivery, and swap and options contracts are generally settled at expiration through a net settlement mechanism. Market risks associated with our derivative instruments 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.

Exchange-traded futures and options contracts are guaranteed by the NYMEX and, as a result, have minimal credit risk. We are subject to credit risk with over-the-counter forward, swap and options 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.

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 plus¹/⁄₂ of 1% or the agent bank’s prime rate, or LIBOR plus 1%, plus the applicable margin. The applicable margin is dependent on the level of the Partnership’s total consolidated leverage ratio (the ~~total~~ ratio of consolidated total debt to consolidated 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 ~~29, 2012,~~28, 2013, the fair value of the interest rate swaps was a net liability of ~~$5.5~~$2.4 million, which is included within other current liabilities and other liabilities, as applicable, with a corresponding unrealized loss reflected in accumulated other comprehensive income.

All of our derivative instruments are reported on the balance sheet at their fair values. On the date that derivative instruments are entered into, we make a determination as to whether the derivative instrument qualifies for designation as a hedge. Changes in the fair value of derivative instruments are recorded each period in current period earnings or OCI, depending on whether a derivative instrument is designated as a hedge and, if so, the type of hedge. For derivative instruments designated as cash flow hedges, we formally assess, both at the hedge contract’s inception and on an ongoing basis, whether the hedge contract is highly effective in offsetting changes in cash flows of hedged items. Changes in the fair value of derivative instruments designated as cash flow hedges are reported in OCI to the extent effective and reclassified into earnings during the same period in which the hedged item affects earnings. The mark-to-market gains or losses on ineffective portions of cash flow hedges are immediately recognized in earnings. Changes in the fair value of derivative instruments that are not designated as cash flow hedges, and that do not meet the normal purchase and normal sale exemption, are recorded in earnings as they occur. Cash flows associated with derivative instruments are reported as operating activities within the consolidated statement of cash flows.

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:

Based on the sensitivity analysis described above, the hypothetical 10% adverse change in market prices for open ~~futures and option contracts~~derivative instruments as of September ~~29, 2012~~28, 2013 indicates an increase in potential future net losses of ~~$1.7~~$2.2 million as of September ~~29, 2012.~~28, 2013. 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.

Our Consolidated Financial Statements and the Report of Independent Registered Public Accounting Firm thereon listed on the accompanying Index to Financial Statements in Part IV, Item 15 (see page F-1) and the Supplemental Financial Information listed on the accompanying Index to Financial Statement Schedule in Part IV, Item 15 (see page S-1) are included herein.

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


	First			Second			Third			Fourth			Total			First			Second			Third			Fourth			Total
	Quarter			Quarter			Quarter			Quarter (a)			Year			Quarter			Quarter			Quarter			Quarter (a)			Year
Fiscal 2012
Fiscal 2013
Revenues	$	299,886		$	357,626		$	179,601		$	226,345		$	1,063,458		$	490,703		$	678,426		$	290,805		$	243,672		$	1,703,606
Cost of products sold		183,574			208,401			88,776			118,308			599,059			245,100			346,999			148,176			121,630			861,905
Operating income (loss)		30,290			56,125			(2,744	)		(40,770	)		42,901			82,308			153,977			(20,654	)		(38,655	)		176,976
Loss on debt extinguishment (b)		—			507			—			1,742			2,249			—			—			—			2,144			2,144
Net income (loss)		23,232			49,573			(9,323	)		(61,600	)		1,882			57,620			129,484			(45,187	)		(63,119	)		78,798
Net income (loss) per common unit—basic (c)		0.65			1.39			(0.26	)		(1.29	)		0.05			1.05			2.29			(0.77	)		(1.05	)		1.35
Net income (loss) per common unit—diluted (c)		0.65			1.38			(0.26	)		(1.29	)		0.05			1.04			2.28			(0.77	)		(1.05	)		1.34

Cash provided by (used in)
Operating activities		(25,323	)		42,371			56,202			37,723			110,973			61,537			72,426			66,505			13,838			214,306
Investing activities		(4,714	)		(2,775	)		(4,528	)		(227,741	)		(239,758	)		1,847			(4,999	)		(6,532	)		(4,979	)		(14,663	)
Financing activities		(30,226	)		(32,684	)		(32,072	)		208,531			113,549			(48,605	)		(49,965	)		93,459			(221,617	)		(226,728	)
EBITDA (d)	$	38,075		$	63,267		$	5,728		$	(20,628	)	$	86,442		$	112,835		$	185,293		$	10,850		$	(3,762	)	$	305,216
Adjusted EBITDA (d)	$	39,123		$	65,852		$	3,460		$	101		$	108,536		$	117,473		$	190,668		$	19,171		$	1,941		$	329,253
Retail gallons sold
Propane		74,279			89,941			49,014			70,607			283,841			153,933			210,314			92,109			78,265			534,621
Fuel oil and refined fuels		7,695			10,565			4,314			5,917			28,491			15,885			23,223			8,331			6,271			53,710

Fiscal 2011
Fiscal 2012
Revenues	$	328,307		$	464,102		$	216,563		$	181,580		$	1,190,552		$	299,886		$	357,626		$	179,601		$	226,345		$	1,063,458
Cost of products sold		186,504			259,832			125,175			107,208			678,719			183,574			208,401			88,776			118,308			599,059
Severance charges		—			2,000			—			—			2,000
Operating income (loss)		50,341			107,233			353			(14,699	)		143,228			30,290			56,125			(2,744	)		(42,014	)		41,657
Loss on debt extinguishment (b)																	—			507			—			1,742			2,249
Net income (loss)		43,129			100,316			(6,787	)		(21,692	)		114,966			23,232			49,573			(9,323	)		(62,844	)		638
Net income (loss) per common unit—basic (c)		1.22			2.82			(0.19	)		(0.61	)		3.24			0.65			1.39			(0.26	)		(1.32	)		0.02
Net income (loss) per common unit—diluted (c)		1.21			2.81			(0.19	)		(0.61	)		3.22			0.65			1.38			(0.26	)		(1.32	)		0.02

Cash provided by (used in)
Operating activities		(4,858	)		54,696			60,003			22,945			132,786			(25,323	)		42,371			56,202			37,723			110,973
Investing activities		(6,390	)		(3,194	)		(5,285	)		(4,636	)		(19,505	)		(4,714	)		(2,775	)		(4,528	)		(227,741	)		(239,758	)
Financing activities		(30,062	)		(30,177	)		(30,194	)		(30,203	)		(120,636	)		(30,226	)		(32,684	)		(32,072	)		208,531			113,549
EBITDA (d)	$	58,521		$	115,687		$	10,023		$	(5,375	)	$	178,856		$	38,075		$	63,267		$	5,728		$	(20,628	)	$	86,442
Adjusted EBITDA (d)	$	60,094		$	113,564		$	10,336		$	(4,569	)	$	179,425		$	39,123		$	65,852		$	3,460		$	101		$	108,536
Retail gallons sold
Propane		86,286			114,034			54,629			43,953			298,902			74,279			89,941			49,014			70,607			283,841
Fuel oil and refined fuels		11,393			16,249			5,621			3,978			37,241			7,695			10,565			4,314			5,917			28,491

(b)

During the fourth quarter of fiscal 2013, we repurchased pursuant to an optional redemption $133.4 million of our 2021 Senior Notes using net proceeds from our May 2013 public offering and net proceeds from the underwriters’ exercise of their over-allotment option to purchase additional Common Units. In addition, we repurchased $23.9 million of our 2021 Senior Notes in a private transaction using cash on hand. In connection with these repurchases, which totaled $157.3 million in aggregate principal amount, we recognized a loss on the extinguishment of debt of $2.1 million consisting of $11.7 million for the repurchase premium and related fees, as well as the write-off of $2.1 million and ($11.7) million in unamortized debt origination costs and unamortized premium, respectively. During the second quarter of fiscal 2012, we amended the Credit Agreement (the “Amended Credit Agreement”) that provides for a five-year $250.0 million revolving credit facility (the “Revolving Credit Facility”), of which, $100.0 million was outstanding as of September 29, 2012 to extend the maturity date from June 25, 2013 to January 5, 2017. In connection with the execution of the Amended Credit Agreement, we recognized a non-cash charge of $0.5 million to write-off a portion of unamortized debt origination costs associated with the previous credit agreement, and capitalized $2.4 million for origination costs incurred with the amendment. During the fourth quarter of fiscal 2012, we amended the Amended Credit Agreement that provides for a five-year $400.0 million revolving credit facility, of which, $100.0 million was outstanding as of September 29, 2012. In connection with the execution of the Amendment Credit Agreement, we recognized a non-cash charge of $1.7 million to write-off a portion of unamortized debt origination costs associated with the previous credit agreement.


	First			Second			Third			Fourth			Total			First			Second			Third			Fourth			Total
	Quarter			Quarter			Quarter			Quarter			Year			Quarter			Quarter			Quarter			Quarter			Year
Fiscal 2012
Fiscal 2013
Net income (loss)	$	23,232		$	49,573		$	(9,323	)	$	(61,600	)	$	1,882		$	57,620		$	129,484		$	(45,187	)	$	(63,119	)	$	78,798
Add:
Provision for income taxes		220			(380	)		100			197			137			132			150			148			177			607
Interest expense, net		6,838			6,425			6,479			18,891			38,633			24,556			24,343			24,385			22,143			95,427
Depreciation and amortization		7,785			7,649			8,472			21,884			45,790			30,527			31,316			31,504			37,037			130,384

EBITDA		38,075			63,267			5,728			(20,628	)		86,442			112,835			185,293			10,850			(3,762	)		305,216
Unrealized (non-cash) losses (gains) on changes in fair value of derivatives		1,048			—			(8,218	)		2,521			(4,649	)		3,614			2,646			73			(2,015	)		4,318
Acquisition-related costs		—			—			5,950			11,966			17,916
Loss on legal settlement		—			—			—			4,500			4,500
Integration related costs																	1,024			2,729			2,248			4,574			10,575
Multi-employer pension plan withdrawal charge																	—			—			6,000			1,000			7,000
Loss on debt extinguishment		—			507			—			1,742			2,249			—			—			—			2,144			2,144
Loss on asset disposal		—			2,078			—			—			2,078

Adjusted EBITDA		39,123			65,852			3,460			101			108,536			117,473			190,668			19,171			1,941			329,253
Add (subtract):
Provision for income taxes		(220	)		380			(100	)		(197	)		(137	)		(132	)		(150	)		(148	)		(177	)		(607	)
Interest expense, net		(6,838	)		(6,425	)		(6,479	)		(18,891	)		(38,633	)		(24,556	)		(24,343	)		(24,385	)		(22,143	)		(95,427	)
Unrealized (non-cash) (losses) gains on changes in fair value of derivatives		(1,048	)		—			8,218			(2,521	)		4,649			(3,614	)		(2,646	)		(73	)		2,015			(4,318	)
Acquisition-related costs		—			—			(5,950	)		(11,966	)		(17,916	)
Loss on legal settlement		—			—			—			(4,500	)		(4,500	)
Integration related costs																	(1,024	)		(2,729	)		(2,248	)		(4,574	)		(10,575	)
Multi-employer pension plan withdrawal charge																	—			—			(6,000	)		(1,000	)		(7,000	)
Compensation cost recognized under Restricted Unit Plans		1,203			1,147			911			798			4,059			1,240			1,173			840			635			3,888
(Gain) loss on disposal of property, plant and equipment, net		(32	)		(179	)		(35	)		(481	)		(727	)
Gain on disposal of property, plant and equipment, net																	(2,267	)		(323	)		(301	)		(652	)		(3,543	)
Changes in working capital and other assets and liabilities		(57,511	)		(18,404	)		56,177			75,380			55,642			(25,583	)		(89,224	)		79,649			37,793			2,635

Net cash (used in) provided by operating activities	$	(25,323	)	$	42,371		$	56,202		$	37,723		$	110,973
Net cash provided by operating activities																$	61,537		$	72,426		$	66,505		$	13,838		$	214,306


	First			Second			Third			Fourth			Total			First			Second			Third			Fourth			Total
	Quarter			Quarter			Quarter			Quarter			Year			Quarter			Quarter			Quarter			Quarter			Year
Fiscal 2011
Fiscal 2012
Net income (loss)	$	43,129		$	100,316		$	(6,787	)	$	(21,692	)	$	114,966		$	23,232		$	49,573		$	(9,323	)	$	(62,844	)	$	638
Add:
Provision for income taxes		366			98			273			147			884
Provision for (benefit from) income taxes																	220			(380	)		100			197			137
Interest expense, net		6,846			6,819			6,867			6,846			27,378			6,838			6,425			6,479			18,891			38,633
Depreciation and amortization		8,180			8,454			9,670			9,324			35,628			7,785			7,649			8,472			23,128			47,034

EBITDA		58,521			115,687			10,023			(5,375	)		178,856			38,075			63,267			5,728			(20,628	)		86,442
Unrealized (non-cash) losses (gains) on changes in fair value of derivatives		1,573			(4,123	)		313			806			(1,431	)		1,048			—			(8,218	)		2,521			(4,649	)
Severance charges		—			2,000			—			—			2,000
Acquisition-related costs																	—			—			5,950			11,966			17,916
Loss on legal settlement																	—			—			—			4,500			4,500
Loss on debt extinguishment																	—			507			—			1,742			2,249
Loss on asset disposal																	—			2,078			—			—			2,078

Adjusted EBITDA		60,094			113,564			10,336			(4,569	)		179,425			39,123			65,852			3,460			101			108,536
Add (subtract):
Provision for income taxes		(366	)		(98	)		(273	)		(147	)		(884	)
(Provision for) benefit from income taxes																	(220	)		380			(100	)		(197	)		(137	)
Interest expense, net		(6,846	)		(6,819	)		(6,867	)		(6,846	)		(27,378	)		(6,838	)		(6,425	)		(6,479	)		(18,891	)		(38,633	)
Unrealized (non-cash) (losses) gains on changes in fair value of derivatives		(1,573	)		4,123			(313	)		(806	)		1,431			(1,048	)		—			8,218			(2,521	)		4,649
Severance charges		—			(2,000	)		—			—			(2,000	)
Compensation cost recognized under Restricted Unit Plans		1,332			1,067			737			786			3,922
(Gain) loss on disposal of property, plant and equipment, net		(299	)		(2,612	)		67			72			(2,772	)
Acquisition-related costs																	—			—			(5,950	)		(11,966	)		(17,916	)
Loss on legal settlement																	—			—			—			(4,500	)		(4,500	)
Compensation cost recognized under
Restricted Unit Plans																	1,203			1,147			911			798			4,059
Gain on disposal of property, plant and equipment, net																	(32	)		(179	)		(35	)		(481	)		(727	)
Changes in working capital and other assets and liabilities		(57,200	)		(52,529	)		56,316			34,455			(18,958	)		(57,511	)		(18,404	)		56,177			75,380			55,642

Net cash (used in) provided by operating activities	$	(4,858	)	$	54,696		$	60,003		$	22,945		$	132,786		$	(25,323	)	$	42,371		$	56,202		$	37,723		$	110,973

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 ~~29, 2012.~~28, 2013. 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 ~~29, 2012.~~28, 2013.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING. ~~Other than changes resulting from the Inergy Propane Acquisition discussed below, there~~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 ~~29, 2012,~~28, 2013, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. Management’s Report on Internal Control over Financial Reporting is included below.

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

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

The Partnership’s management has assessed the effectiveness of the Partnership’s internal control over financial reporting as of September ~~29, 2012.~~28, 2013. In making this assessment, the Partnership used the criteria established by the Committee of Sponsoring Organizations of the Treadway Commission ~~(COSO)~~(“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~~Partnership’s assessment included documenting, evaluating and testing the design and operating effectiveness of its internal control over financial reporting.

We have excluded from our assessment the internal control over financial reporting of Inergy Propane, which was acquired on August 1, 2012, and whose total assets and total revenue represent 25% and 7%, respectively, of the related consolidated financial statement amounts as of and for the fiscal year ended September 29, 2012. Based on the Partnership’s assessment, as described above, management has concluded that, as of September ~~29, 2012,~~28, 2013, the Partnership’s internal control over financial reporting was effective. The Partnership is currently in the process of integrating Inergy Propane’s operations, processes and internal controls. Refer to Note 3—Acquisition of Inergy Propane included within the Notes to the Consolidated Financial Statements section elsewhere in this Annual Report.

Our independent registered public accounting firm, PricewaterhouseCoopers LLP, issued an attestation report dated November ~~28, 2012~~27, 2013 on the effectiveness of our internal control over financial reporting, which is included herein.

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. Under the current Partnership Agreement, members of our Board of Supervisors are elected by the Unitholders for three-year terms. All six of our current Supervisors who were serving in such capacity at the ~~end~~beginning of our ~~2012~~2013 Fiscal Year were elected to their current three-year terms at the Tri-Annual Meeting of our Unitholders convened on May 1, 2012 and then reconvened on May 14, 2012.

At its regular meeting on November 13, 2012, our Board of Supervisors, pursuant to authority granted to the Board under the Partnership Agreement, increased the size of the Board from six (6) Supervisors to eight (8) Supervisors. At the same meeting and again pursuant to authority granted to the Board under the Partnership Agreement, the Board elected Messrs. Lawrence C. Caldwell and Matthew J. Chanin to fill the two vacancies on the Board created by the increase in size of the Board, effective immediately. Messrs. Caldwell and Chanin were each elected for a term due to expire at the next Tri-Annual Meeting of our Unitholders, currently scheduled for Spring 2015. At that meeting, Messrs. Caldwell and Chanin were also named to the Audit and Compensation Committees.

Seven Supervisors, who are not officers or employees of the Partnership or its subsidiaries, now 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,~~SEC, 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)~~(i) integrity of the Partnership’s financial statements and internal control over financial reporting; ~~(b)~~(ii) the Partnership’s compliance with applicable laws, regulations and its code of conduct; ~~(c)~~(iii) independence and qualifications of the independent registered public accounting firm; ~~(d)~~(iv) performance of the internal audit function and the independent registered public accounting firm; and ~~(e)~~(v) accounting complaints.

The Board of Supervisors has determined that all seven members of the Audit Committee, Harold R. Logan, Jr., John Hoyt Stookey, Dudley C. Mecum, John D. Collins, Lawrence C. Caldwell, Matthew J. Chanin and Jane Swift are independent and (with the exception of Ms. Swift) are audit committee financial experts within the meaning of the NYSE corporate governance listing standards and in accordance with Rule 10A-3 of the Exchange Act, Item 407 of Regulation S-K and the Partnership’s criteria for Supervisor independence (as discussed in Item 13, herein) as of the date of this Annual Report.

Mr. Logan, Chairman of the Board, presides at the regularly scheduled executive sessions of the non-management Supervisors, all of whom are independent, held as part of the meetings of the Audit Committee. Investors and other parties interested in communicating directly with the non-management Supervisors as a group may do so by writing to the Non-Management Members of the Board of Supervisors, c/o Company Secretary, Suburban Propane Partners, L.P., P.O. Box 206, Whippany, New Jersey ~~07981-0206.~~07981-0206

The following table sets forth certain information with respect to the members of the Board of Supervisors and our executive officers as of November ~~28, 2012.~~27, 2013. Officers are appointed by the Board of Supervisors forone-year terms and Supervisors are elected by the Unitholders forthree-year terms.

On November 14, 2013, we announced that, pursuant to a succession plan developed by Mr. Dunn and our Board of Supervisors, Mr. Dunn will relinquish the role of President on March 31, 2014, and will retire as our Chief Executive Officer effective September 27, 2014, the last day of our 2014 fiscal year. Simultaneously, we announced that Mr. Stivala will assume the role of our President on April 1, 2014.

Mr. Dunn has served as our President since May 2005 and as our Chief Executive Officer since September 2009. Mr. Dunn has served as a Supervisor since July 1998. From June 1998 until May 2005 he was our Senior Vice President, becoming Senior Vice President – Corporate Development in November 2002. He was our Vice President – Procurement and Logistics from March 1997 until June 1998. Before joining the Partnership, Mr. Dunn was Vice President of Commodity Trading for the investment banking firm of Goldman Sachs & Company (“Goldman Sachs”). Mr. Dunn is the sole member of the General Partner.

Mr. Dunn’s qualifications to sit on our Board include his more than 15 years of experience in the propane industry, including as our President for the past 78 years and Chief Executive Officer for the past 34 years, which day to day leadership roles have provided him with intimate knowledge of our operations.

Mr. Stivala has served as our Chief Financial Officer since November 2009, and, before that, as our Chief Financial Officer and Chief Accounting Officer since October 2007. Prior to that he was our 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 our Senior Vice President – Administration since July 2009. From July 1996 to that date he was our Vice President – Human Resources and Administration. He previously held senior human resource positions at Hanson Industries (the United States management division of Hanson plc, a global diversified industrial conglomerate) and Quantum Chemical Corporation (“Quantum”), a predecessor of the Partnership.

Mr. D’Ambrosio has served as our Treasurer since November 2002 and was additionally made a Vice President in October 2007. He served as our 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 our 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. Boyd has served as our Vice President – Field Operations (formerly Vice President – Operations) since October 2008. Prior to that he was our 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 our 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. Kuglin has served as our Vice President and Chief Accounting Officer since November 2011. Prior to that he was our 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. Scanlon became our Vice President – Information Services in November 2008. Prior to that he served as our 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, an international systems consulting firm, most recently as Manager.

Mr. Wienberg has served as our Vice President – Operational Support and Analysis (formerly Vice President – Operational Planning) since October 2007. Prior to that he served as our 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.

Ms. Zwickel has served as our Vice President – Human Resources since November 2013. Prior to that, she was our Assistant Vice President – Human Resources since April 2011 and earlier held several roles in the Partnership’s Legal Department (including Assistant General Counsel from October 2009 to April 2011 and Counsel from October 2002 to October 2009), where she was responsible for, among other things, providing legal counsel on employment issues. Ms. Zwickel joined the Partnership in June 1999 after eight years in the private practice of law.

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

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

Mr. Stookey has served as a Supervisor since March 1996. He was Chairman of the Board of Supervisors from March 1996 through January 2007. From 1986 until September 1993, he was the Chairman, President and Chief Executive Officer of Quantum. He served as non-executive Chairman and a Director of Quantum from its acquisition by Hanson plc in September 1993 until October 1995, at which time he retired. Since then, Mr. Stookey has served as a trustee ~~for~~of 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~~training inner city individuals to ~~improve the lives of residents of the South Bronx)~~become computer and software technicians), The Berkshire Choral Festival and Landmark Volunteers ~~(places high school students in volunteer positions with non-profit organizations during summer vacations)~~ and ~~has~~ also ~~served~~serves on the Board of Directors of The Clark Foundation and The Robert Sterling Clark Foundation and ~~The Berkshire Taconic Community Foundation.~~as a Life Trustee of the Boston Symphony Orchestra.

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

Mr. Mecum has served as a Supervisor since June 1996. He was a Managing Director of Capricorn Holdings, LLC (a sponsor of and investor in leveraged buyouts) from 1997 to 2011 and a partner of G.L. Ohrstrom & Co. (a sponsor of and investor in leveraged buyouts) from 1989 to 1996. ~~Until 2007, Mr. Mecum was a director of Citigroup, Inc.~~

Mr. Mecum’s qualifications to sit on our Board include his 20 years in public accounting, rising to the level of Vice Chairman of KPMG LLP, a public accounting firm, his service as Assistant Secretary of the Army for Installations and Logistics and his 15 years of service overseeing or managing various companies. Mr. Mecum has over 20 years of service as a director of various publicly-owned ~~companies.~~companies, including, until 2007, Citigroup, Inc.

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

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

Ms. Swift has served as a Supervisor since April 2007. She is currently the CEO of Middlebury Interactive Languages, LLC, a marketer of world language products. From 2010 through July 2011, Ms. Swift served as Senior Vice President of ConnectEDU Inc., a private education technology company. In 2007, she founded WNP Consulting, LLC, a provider of expert advice and guidance to early stage education companies. From 2003 to 2006 she was a General Partner at Arcadia Partners, a venture capital firm focused on the education industry. She has previously served on the boards of K12, Inc. and Animated Speech Company and currently serves on the boards of Sally Ride Science Inc. and several not-for-profit boards, including the National Alliance for Public Charter Schools and The ~~Republican Majority for Choice and Landmark Volunteers, Inc.~~Young Writers Project. Prior to joining Arcadia, Ms. Swift served for 15 years in Massachusetts state government, becoming Massachusetts’ first woman governor in 2001.

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

Mr. Caldwell has served as a Supervisor since November 2012. He was a Co-Founder of New Canaan Investments, Inc. (“NCI”), a private equity investment firm, where he was one of three senior officers of the firm from 1988-2005. NCI was an active “fix and build” investor in packaging, chemicals, and automotive components companies. Mr. Caldwell held a number of board directorships and senior management positions in these companies until he retired in 2005. The largest of these companies was Kerr Group, Inc., a plastic closure and bottle company where Mr. Caldwell served as Director for 8 years and Chief Financial Officer for 6 years. From 1985-1988, Mr. Caldwell was head of acquisitions for Moore McCormack Resources, Inc., an oil and gas exploration, shipping, and construction materials company. Mr. Caldwell is currently a director of Magnuson Products, LLC, a private company which manufactures specialty engine components for the automotive OEM and aftermarket. Mr. Caldwell also serves on the Board of Trustees and as Chairman of the Investment and Finance Committee of Historic Deerfield, and on the Board of Directors and as Chairman of both the Finance and Strategic Planning Committees of the Leventhal Map Center, both of which non-profit institutions focus on enriching educational programs for K-12 children locally and nationwide.

Mr. ~~Caldwell's~~Caldwell’s qualifications to sit on our Board include over 40 years of successful investing in and managing of a broad range of public and private businesses in a number of different industries. This experience has encompassed both turnaround situations, and the building of companies through internal growth and acquisitions.

Mr. Chanin has served as a Supervisor since November 2012. He was Senior Managing Director of Prudential Investment Management, a subsidiary of Prudential Financial, Inc., from 1996 until his retirement in January, 2012. He headed the firm’s private fixed income business, chaired an internal committee responsible for strategic investing and was a principal in Prudential Capital Partners, the firm’s mezzanine investment business. He currently serves as a Director of three private companies that are in Prudential Capital Partners funds’ portfolios, and provides consulting services to Prudential and one other client.

Mr. Chanin’s qualifications to sit on our Board include 35 years of investment experience with a focus on highly structured private placements in companies in a broad range of industries, with a particular focus on energy companies. He has previously served on the audit committee of a public company board and is currently a member of the audit committee for a private company board. Mr. Chanin has earned an MBA and is a Chartered Financial Analyst.

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 2012.~~Fiscal Year 2013, except that Matthew J. Chanin filed one Form 4 late with respect to one purchase transaction due to the late transmission of the necessary information by his broker.

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 atwww.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.

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 atwww.suburbanpropane.com or upon written request directed to: Suburban Propane Partners, L.P., Investor Relations, P.O. Box 206, Whippany, New Jersey 07981-0206.

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 atwww.suburbanpropane.com or upon written request directed to: Suburban Propane Partners, L.P., Investor Relations, P.O. Box 206, Whippany, New Jersey 07981-0206.

Seven Supervisors, who are not officers or employees of the Partnership or its subsidiaries, serve on the Compensation Committee. The Board of Supervisors has determined that all seven members of the Compensation Committee, Harold R. Logan, Jr., John Hoyt Stookey, Dudley C. Mecum, John D. Collins, Jane Swift, Lawrence C. Caldwell and Matthew J. Chanin are independent. 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 atwww.suburbanpropane.com or upon written request directed to: Suburban Propane Partners, L.P., Investor Relations, P.O. Box 206, Whippany, New Jersey 07981-0206.

During fiscal 2013, the Compensation Committee independently retained Towers Watson, a compensation consultant, to assist the Compensation Committee in its review and development of a new performance metric under our Long-Term Incentive Plan.

The NYSE requires the Chief Executive Officer of each listed company to submit a certification indicating that the company is not in violation of the Corporate Governance listing standards of the NYSE on an annual basis. Mr. Dunn submits his Annual CEO Certification to the NYSE each December. In December ~~2011,~~2012, Mr. Dunn submitted his Annual CEO Certification to the NYSE without qualification.

This Compensation Discussion and Analysis explains our executive compensation philosophy, policies and practices with respect to the following executive officers of Suburban, which we refer to as the “named executive officers”: Mr. Dunn, our President and Chief Executive Officer; Mr. Stivala, our Chief Financial Officer; and the other three most highly compensated executive ~~officers,~~officers: Mr. Boyd, our Vice President of Field Operations; Mr. Wienberg, our Vice President of Operational Support and Analysis and Mr. Brinkworth, our Vice President of Product Supply.

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:

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:

The Compensation Committee, which we hereafter refer to as the “Committee,” is responsible for overseeing our executive compensation program. In accordance with its charter, available on our website atwww.suburbanpropane.com, the Committee ensures that the compensation packages provided to our executive officers are designed in accordance with our compensation philosophy. The Committee reviews and approves the compensation packages of our managing directors, assistant vice presidents, vice presidents, senior 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, experience, 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 also factors into the decision-making process, particularly in relation to promotions and increases in base compensation. In addition, as part of the Committee’s annual review of each executive officer’s total compensation package, the Committee is provided with benchmarking data for comparison. The benchmarking data is just one of a number of factors considered by the Committee, but is not necessarily the most persuasive factor.

The benchmarking data provided to the Committee for fiscal year ~~2012~~2013 was derived from the Mercer Human Resource Consulting, Inc. (“Mercer”) Benchmark Database containing information obtained from surveys of over ~~2,459~~2,543 organizations and approximately ~~210~~209 positions which may or may not 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 benchmarking information used by the Committee consisted of organizations included in the Mercer database that report median annual revenues of between $1.1 billion and ~~$3.7~~$4.2 billion per year.

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

Conversely, for the reasons set forth under the subheading “Long-Term Incentive Plan” below, the Committee decided to include other propane marketers, structured as publicly traded partnerships, in the peer group it selected for measuring our performance for awards granted under the Long-Term Incentive Plan. Earning a payment under the Long-Term Incentive Plan is dependent upon the performance (referred to in the plan document as “total return to unitholders”) of our Common Units relative to the unit performance of a peer group of eleven other master limited partnerships over a three-year measurement period.

In making their decisions regarding executive compensation packages for the coming fiscal year, the members of the Committee review the total cash compensation opportunities that were provided to our executive officers during the just completed fiscal year. Each executive officer’s “total cash compensation opportunity” consists of base salary, an annual cash bonus, and Long-Term Incentive Plan awards. The Committee then compares each executive officer’s total cash compensation opportunity to the total mean cash compensation opportunity for the parallel position in the Mercer database. By focusing on each executive officer’s total cash compensation opportunity as a whole, instead of on single components of compensation such as base salary, when it met on November ~~9, 2011,~~13, 2012, the Committee created fiscal ~~2012~~2013 compensation packages for our executive officers that emphasized the performance-based components of compensation.

AtThe Committee does not base its benchmarking solely on a peer group of other propane marketers, as the Committee believes that the proximity of Suburban’s headquarters to New York City and the need to realistically compete for skilled executives in an environment shared by numerous other enterprises that seek similarly skilled employees requires a broader review of the market. The Committee chooses not to base its benchmarking on the compensation practices of other propane marketers due to the fact that the other, similarly-sized propane marketers compete for executives in vastly different economic environments.

As previously reported, at their fiscal 2012 Tri-Annual Meeting, our Unitholders ~~overwhelming~~overwhelmingly approved the advisory “Say-on-Pay” resolution required by Section 14A of the Exchange ~~Act by~~Act. As a ~~vote~~result, the Committee determined that no major revisions of ~~16,122,718 in favor, 1,092,850 against and 574,454 abstentions. Although~~its practices are required; however, the Committee has, and will continue to, periodically evaluate its compensation practices for possible ~~improvement, after consideration of these results, the Committee has determined that no major changes are required to its practices.~~

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

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

Suburban’s sole use of the Mercer database was to provide the Committee with benchmarking data. Therefore, prior to the November ~~9, 2011~~13, 2012 Committee meeting, neither our President and Chief Executive Officer nor our Senior Vice President of Administration met with representatives from Mercer. The information provided by Mercer was derived from a proprietary database maintained by Mercer and, as such, there was no formal consultancy role played by them. The Committee believes that the Mercer benchmarking data, which is provided to the Committee by our Senior Vice President of Administration, can be used by the Committee as an objective benchmark on which decisions relative to executive compensation can be based. In the course of its deliberations, the Committee compares the objective data obtained from the Mercer database to the internal analyses prepared by our Senior Vice President of Administration.

Under our compensation structure, the mix of base salary, cash bonus and long-term compensation provided to each executive officer varies depending on his or her position. The base salary for each executive officer is the only fixed component of compensation. All other cash compensation, including annual cash bonuses and long-term incentive compensation, is variable in nature as it is dependent upon achievement of certain performance measures. The following table summarizes the components as percentages of each named executive officer’s total cash compensation opportunity in fiscal ~~2012~~2013 (as determined at the Committee’s November ~~9, 2011~~13, 2012 meeting).


											Cash	Long-Term
	Base Salary			Cash Bonus Target			Long-Term Incentive			Base Salary	Bonus Target	Incentive
Michael J. Dunn, Jr.		40	%		40	%		20	%	40%	40%	20%
Michael A. Stivala		45	%		36	%		19	%	45%	36%	19%
Steven C. Boyd		45	%		36	%		19	%	45%	36%	19%
Mark Wienberg		45	%		36	%		19	%	45%	36%	19%
Douglas T. Brinkworth		45	%		36	%		19	%	45%	36%	19%

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

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 Suburban, individual performance and years of experience in his ~~or her~~ current position. The relative importance assigned to each of these factors by the Committee may differ from executive to executive. The Committee will also consider the existing level of equity ownership of each of our named executive officers when granting awards under our Restricted Unit Plans (see below for a description of these plans). As a result, different weights may be given to different components of compensation among each of our named executive officers. In addition, as discussed in the section above titled “Allocation Among Components,” the compensation packages that we provide to our senior-most levels of management are, at a minimum, 50% performance-based. In order to align the interests of senior management with the interests of our Unitholders, we consider it requisite to accentuate the performance-based elements of the compensation packages that we provide to these individuals.

Base salaries for the named executive officers and all of our other executive officers, are reviewed and approved annually by the Committee. In order to determine base salary increases, the Committee’s practice is to compare each executive officer’s base salary with the corresponding mean salary provided in the Mercer database. The Committee usually determines base salary adjustments, which may be higher or lower than the comparative data, following an assessment of our overall results as well as each executive officer’s position, performance and scope of responsibility, while at the same time considering each executive officer’s previous total cash compensation opportunities. In accordance with this process and the philosophy described above, ~~the Committee did not adjust the base salaries of the named executive officers during fiscal 2012.~~

~~In the event of a promotion, a significant increase~~and in an executive officer’s responsibilities, or a new hire, it is the Committee’s practice to review that executive officer’s base salary at that time and take such action as the Committee deems warranted. No such actions were taken by the Committee during fiscal 2012.

~~The total base salary paid to each named executive officer in fiscal 2012, fiscal 2011 and fiscal 2010 is reported in the column titled “Salary” in the Summary Compensation Table below.~~

In consideration of the increased responsibilities assumed by our named executive officers as a result of the Inergy Propane Acquisition, at its meeting on November 13, 2012, the Committee made the following adjustments to the base salaries of our named executive officers for fiscal 2013:


Name	Fiscal 2013 Base Salary		Fiscal 2012 Base Salary		Fiscal 2013 Base Salary		Fiscal 2012 Base Salary
Michael J. Dunn, Jr.	$	495,000	$	475,000	$	495,000	$	475,000

Michael A. Stivala	$	300,000	$	275,000	$	300,000	$	275,000

Steven C. Boyd	$	290,000	$	270,000	$	290,000	$	270,000

Mark Wienberg	$	280,000	$	250,000	$	280,000	$	250,000

Douglas T. Brinkworth	$	270,000	$	245,000	$	270,000	$	245,000

In the event of a promotion, a significant increase in an executive officer’s responsibilities, or a new hire, it is the Committee’s practice to review that executive officer’s base salary at that time and take such action as the Committee deems warranted. At its meeting on November 13, 2013, the Committee did not adjust the base salaries of our named executive officers for fiscal 2014.

The total base salary paid to each named executive officer in fiscal 2013, fiscal 2012 and fiscal 2011 is reported in the column titled “Salary” in the Summary Compensation Table below.

Annual cash bonuses (which fall within the Securities and Exchange Commission’s definition of “Non-Equity Incentive Plan Compensation” for the purposes of the Summary Compensation Table and otherwise) are earned by our executive officers in accordance with the objective performance provisions of our annual cash bonus plan.

The terms of our annual cash bonus plan provide for cash payments of a specified percentage (which, in fiscal ~~2012,~~2013, ranged from 80% to 100%) of our named executive officers’ annual base salaries (“target cash bonus”) if, for the fiscal year, actual cash bonus plan EBITDA equals Suburban’s budgeted EBITDA. For purposes of calculating cash bonus plan EBITDA, the Committee customarily adjusts both budgeted and actual EBITDA (as defined in Item 6 in this annual report on Form 10-K) for various items considered to be non-recurring in nature; including, but not limited to, unrealized (non-cash) gains or losses on changes in the fair value of derivative ~~instruments reported within cost of products sold in our statement of operations~~instruments; acquisition-related costs; integration-related costs; multiemployer pension plan withdrawal charges; pension settlement charges; and ~~gains or~~ losses on ~~the disposal of discontinued operations.~~debt extinguishment. Under the ~~previous~~ annual cash bonus plan, ~~executive officers had the opportunity to earn between 90% and 110% of their target cash bonuses; however, beginning with fiscal 2011,~~our executive officers have ~~had~~ the opportunity to earn between 60% and 120% of their target cash bonuses, depending upon Suburban’s EBITDA performance in the fiscal ~~year. Under the existing annual cash bonus plan,~~year; no bonuses are earned if actual cash bonus plan EBITDA is less than 90% of budgeted cash bonus plan EBITDA, and cash bonuses cannot exceed 120% of the target cash bonus even if actual cash bonus plan EBITDA is more than 120% of budgeted cash bonus plan EBITDA.

Although our annual cash bonus plan is generally administered using the formula described above, the Committee may exercise its broad discretionary powers to decrease or increase the annual cash bonus paid to a particular executive officer, upon the recommendation of our President and Chief Executive Officer, or the executive officers as a group, when the Committee recognizes that an adjustment is warranted. During fiscal 2013, fiscal 2012 and fiscal 2011, ~~and fiscal 2010,~~ no such discretionary adjustments were made to the annual cash bonuses earned by our executives.

For fiscal ~~2012,~~2013, our budgeted cash bonus plan EBITDA was ~~$187~~$365 million (“Budgeted EBITDA”). Our actual cash bonus plan EBITDA was such that each of our executive officers earned 0%60% of his or her target cash bonus. The following table provides the fiscal ~~2012~~2013 budgeted cash bonus plan EBITDA targets that were established at the November ~~9, 2011~~13, 2012 Committee meeting:

The fiscal ~~2012~~2013 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 ~~2012~~2013 are summarized as follows:


Name	2012 Target Cash Bonus as a % of Base Salary	2012 Target Cash Bonus		2012 Actual Cash Bonus Earned		2013 Target Cash Bonus as a % of Base Salary	2013 Target Cash Bonus		2013 Actual Cash Bonus Earned at 60%
Michael J. Dunn, Jr.	100%	$	475,000	$	-0-	100%	$	495,000	$	297,000

Michael A. Stivala	80%	$	220,000	$	-0-	80%	$	240,000	$	144,000

Steven C. Boyd	80%	$	216,000	$	-0-	80%	$	232,000	$	139,200

Mark Wienberg	80%	$	200,000	$	-0-	80%	$	224,000	$	134,400

Douglas T. Brinkworth	80%	$	196,000	$	-0-	80%	$	216,000	$	129,600

For purposes of establishing the cash bonus targets for fiscal ~~2012,~~2013, the Committee reviewed and approved our fiscal ~~2012~~2013 budgeted cash bonus plan EBITDA at its November ~~9, 2011~~13, 2012 meeting. The budgeted cash bonus plan EBITDA is developed annually using a bottom-up process factoring in reasonable growth targets from the prior year’s performance, while at the same time attempting to reach a balance between a target that is reasonably achievable, yet not assured. As described above, executive officers ~~now~~ have the opportunity to earn between 60% and 120% of their target cash bonuses. Over the past three years, our actual cash bonus plan EBITDA was such that each of our executive officers earned 0%60%, ~~60%~~0% and ~~100%~~60% of their respective target cash bonus for fiscal 2013, fiscal 2012 and fiscal 2011, respectively.

The named executive officers’ target cash bonus percentages and target cash bonuses for fiscal ~~2010, respectively.~~2014 are the same as those for fiscal 2013. Actual payments for fiscal 2014 under the annual cash bonus plan will depend upon the percentage of the budgeted cash bonus plan EBITDA for fiscal 2014 that is eventually achieved. The budgeted cash bonus plan EBITDA for fiscal 2014 was established using the same bottom-up process described above.

The bonuses earned under the annual cash bonus plan for fiscal ~~2011~~2013 and ~~2010~~2011 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 named executive officers’ target cash bonus percentages for fiscal 2013 are the same as those for fiscal 2012. Actual payments for fiscal 2013 under the annual cash bonus plan will depend upon the percentage of the budgeted cash bonus plan EBITDA for fiscal 2013 that is eventually achieved. The budgeted cash bonus plan EBITDA for fiscal 2013 was established using the same bottom-up process described above, which is designed to reach a good balance between a target that is reasonably achievable, yet not assured. Although the target cash bonus percentages for fiscal 2013 remain the same as those for 2012, the target cash bonuses for fiscal 2013 have changed in tandem with the fiscal 2013 changes to our named executive officers’ base salaries as follows:

~~2003 and 2013~~ Long-Term Incentive Plans ~~(which we collectively refer to as the “LTIP”)~~

~~At the beginning of fiscal 2003, we adopted the 2003 Long-Term Incentive Plan, a phantom unit plan, as a principal component of our executive compensation program.~~ While the annual cash bonus plan is a pay-for-performance plan that focuses on our short-term financial goals, the Long-Term Incentive Plans (which we collectively refer to as the “LTIP”) are structured as a LTIP isunit plan that has been designed to motivate our executive officers to focus on our long-term financial goals. ~~Awards~~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 a three-year measurement period, depending on performance.

At the beginning of fiscal 2003, the Committee adopted the 2003 Long-Term Incentive Plan (the “2003 LTIP”) as a principal component of our executive compensation program. At its meeting on November 9, 2011, the Committee adopted the 2013 Long-Term Incentive Plan (the “2013 LTIP”) as a replacement for the 2003 Long-Term Incentive Plan, which expired on September 30, 2012. The 2013 LTIP became effective on October 1, 2012; its provisions were essentially identical to the provisions of the 2003 LTIP. At its meeting on August 6, 2013, the Committee adopted the 2014 Long-Term Incentive Plan (the “2014 LTIP”) as a replacement for the 2013 LTIP. The provisions of the 2014 LTIP govern all LTIP awards granted subsequent to fiscal 2013.

In accordance with the 2003, 2013, and 2014 LTIP documents, at the beginning of each three-fiscal year measurement period, each executive officer’s number of unvested LTIP unit awards is calculated by dividing a predetermined percentage (52% for awards made prior to fiscal 2014 and 50% for all subsequent awards), established by the Committee, 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 first fiscal year in the measurement period.

The following are the numbers of the unvested LTIP units granted to our named executive officers during fiscal 2013 and fiscal 2012 that will be used to calculate cash payments at the end of each award’s respective three-year measurement period (i.e., at the end of fiscal 2015 for the fiscal 2013 award and at the end of fiscal 2014 for the fiscal 2012 award):

At its meeting on November 13, 2013, the Committee approved the grant of the following number of unvested LTIP unit awards under the LTIP for the fiscal 2014 award cycle that commenced at the beginning of fiscal 2014 and will conclude at the end of fiscal 2016 that will be used to calculate cash payments at the end of this award’s three-year measurement period (i.e., at the end of fiscal 2016).

The primary difference between the 2003/2013 LTIPs and the 2014 LTIP is the performance metric used to determine whether cash payouts have been earned by the participants at the end of an LTIP award cycle’s three-year measurement period.

Awards made prior to fiscal 2014 under the 2003 and 2013 LTIPs measure the market performance of our Common Units on the basis of total return to our Unitholders, which we refer to as “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 the current outstanding awards is identical to the prior two years and includes AmeriGas Partners, L.P., Ferrellgas Partners, L.P. and Energy Transfer Partners, 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. At its meeting on November 9, 2011, the Committee adopted the 2013 Long-Term Incentive Plan as a replacement for the 2003 Long-Term Incentive Plan, which expired on September 30, 2012. The 2013 Long-Term Incentive Plan became effective on October 1, 2012, and its provisions are essentially identical to the provisions of the 2003 Long-Term Incentive Plan.

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

The three-year measurement period of the fiscal 2010 award ended simultaneously with the conclusion of fiscal 2012. The TRU for the fiscal 2010 award fell within the lowest quartile; therefore, the participants, including our named executive officers, did not earn cash payouts relative to this award.

The following is a summary of the quantities of phantom units that signify the unvested awards granted to our named executive officers during fiscal 2012 and fiscal 2011 that will be used to calculate cash payments at the end of each award’s respective three-year measurement period (i.e., at the end of fiscal 2014 for the fiscal 2012 award and at the end of fiscal 2013 for the fiscal 2011 award):

The members of the peer groups selected by the Committee for the fiscal 2013, fiscal 2012 and fiscal 2011 ~~and fiscal 2010~~ awards consist entirely of publicly-traded partnerships. The Committee decided upon these peer groups because all publicly-traded partnerships have similar tax attributes and can, as a result, distribute more cash than similarly-sized corporations generating similar revenues. ~~When the Committee makes a decision to replace members of the LTIP peer group, it considers, among other factors, relative size of the company, cash distributions and price trends.~~

The following tables list, in alphabetical order, the names and ticker symbols of the peer group used to measure our performance during three-year measurement periods for the fiscal 2012, fiscal 2011 and fiscal 2010 awards under the LTIP:

A retirement-eligible participant’s outstanding awards will vest as of the retirement-eligible date, but will remain subject to the same three-year measurement period for purposes of determining the eventual cash payout, if any, at the conclusion of the measurement period.

The grant date values based on the probable outcomes of the awards under the LTIP granted during fiscal 2012, fiscal 2011 and fiscal 2010 are reported in the column titled “Unit Awards” in the Summary Compensation Table below.

At its ~~meeting on~~ November 13, 2012 the Committee approved the grant of unvested awards under the LTIP for the fiscal 2013 award cycle which began at the beginning of fiscal 2013 and will conclude at the end of fiscal 2015. Additionally, at this meeting, the Committee approved modifications to the peer group in response to significant changes in the capital structure of several members of the previous peer group, including that of Suburban as a result of the Inergy Propane Acquisition. In choosing this new peer group, the Committee particularly considered the market capitalization and relative similarities in capital structure between the peer group members and Suburban.

The following ~~is a summary~~tables list, in alphabetical order, the names and ticker symbols of the quantities of phantom units that signify the unvested awards granted to our named executive officers under the LTIP during fiscal 2013. These quantities will be used to calculate cash payments at the end of this award’s three-year measurement period (i.e., at the end of fiscal 2015).

~~The~~ peer group ~~selected by the Committee~~used to measure our performance during ~~this award’s~~the three-year measurement ~~period is as follows:~~periods for the fiscal 2013, 2012 and fiscal 2011 awards under the LTIP:

(2)

Inergy Midstream, L.P. merged with Crestwood Midstream Partners LP on October 7, 2013. The combined partnership is named Crestwood Midstream Partners LP and trades under ticker CMLP on the New York Stock Exchange. In addition, Inergy, L.P., the owner of CMLP’s general partner, has been renamed Crestwood Equity Partners, LP. The NYSE ticker symbol was changed from NRGY to CEQP. For purposes of measuring the fiscal 2013 and 2012 awards, as a result of this event, we have reduced the peer groups of those awards by one member.

The three-year measurement period of the fiscal 2011 award ended simultaneously with the conclusion of fiscal 2013. The TRU for the fiscal 2011 award fell within the lowest quartile; therefore, the participants, including our named executive officers, did not earn cash payouts relative to this award.

Subsequent to the Committee’s meeting on November 13, 2012, the Committee reconsidered the use of TRU as the performance metric for purposes of the LTIP. As a result, the Committee engaged the services of Towers Watson to review the LTIP’s measurement criteria. At the Committee’s July 24, 2013 meeting, Towers Watson presented the Committee with a recommendation to replace TRU with a performance metric that measures our average distribution coverage ratio over a three-year measurement period.

The Committee’s decision to replace the 2013 LTIP with the 2014 LTIP was based on its determination that an incentive structure focused on the level of distributable cash flow over a three-year measurement period, which supports the sustainability of the cash distributions to Unitholders and future growth in distributions, is a more meaningful indicator of the Partnership’s performance than comparative TRU, and also better aligns management’s interests with those of the Unitholders.

As a result of the Committee’s adoption of the 2014 LTIP, the earning of payments under the 2014 LTIP will be determined based on the level our distribution coverage ratio over a three-year measurement period. This ratio will be calculated by dividing our average distributable cash flow generated during an outstanding award’s three-year measurement period by a baseline cash flow set on the initial grant date of the award.

The average distributable cash flow is the average of the distributable cash flow for each of the three years in a particular award’s three-year measurement period. For purposes of this plan’s performance metric, distributable cash flow is equal to adjusted EBITDA for a particular fiscal year less capital expenditures, cash interest expense, and the provision for income taxes for the same fiscal year. For LTIP purposes, “adjusted EBITDA” is identical to cash bonus plan EBITDA. The average distributable cash flow will be adjusted by the sum of the annual differences between the per-Common Unit ~~Plan~~annualized distribution rate at the beginning of the three-year measurement period and the actual per-Common Unit distributions paid during each of the three years in an award’s three-year measurement period. Baseline cash flow is calculated by multiplying the total number of Common Units outstanding at the beginning of the three-year measurement period by the then per Common Unit annualized distribution rate.

For awards granted under the 2003 and ~~2009~~ 2013 LTIP plan documents (i.e., the fiscal 2013, the fiscal 2012, and the fiscal 2011 awards), 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:

For awards granted under the 2014 plan document (the first of which will be the fiscal 2014 award, payable, if at all, at the end of fiscal 2016), at the end of the three-year measurement period, depending on the distribution coverage ratio for that three-year measurement period, our executive officers, as well as the other participants, all of whom are key employees, will receive cash payouts equal to:

We adopted the 2000 Restricted Unit Plan effective November 1, 2000. Upon adoption, this plan authorized the issuance of 487,805 Common Units to our executive officers, managers and other employees and to the members of our Board of Supervisors. On October 17, 2006, following approval by our Unitholders, we adopted amendments to this plan which, among other things, increased the number of Common Units authorized for issuance under this plan by 230,000 for a total of 717,805. As this plan terminated by its terms on October 31, 2010, no future awards can be made under this plan; however such termination will not affect the continued validity of any awards granted under the plan prior to its termination.

At our July 22, 2009 Tri-Annual Meeting, our Unitholders approved our adoption of the 2009 Restricted Unit Plan effective August 1, 2009. Upon adoption, this plan authorized the issuance of 1,200,000 Common Units to our executive officers, managers and other employees and to the members of our Board of Supervisors. The provisions of both restricted unit plans are substantially identical. At the conclusion of fiscal ~~2012,~~2013, there remained ~~870,198~~668,860 restricted units available under the RUP for future awards.

When the Committee authorizes an award of restricted units, the unvested units underlying an award do not provide the grantee with voting rights and do not receive distributions or accrue rights to distributions during the vesting period. Restricted unit awards granted prior to August 6, 2013 normally vest as follows: 25% on each of the third and fourth anniversaries of the grant date and the remaining 50% on the fifth anniversary of the grant date. At its August 6, 2013 meeting, the Committee amended the Partnership’s 2009 Restricted Unit Plan to revise the normative vesting schedule of awards granted thereafter to 33.33% on each of the first three anniversaries of the award grant date. The Committee retained the ability to deviate, at its discretion, from the normal vesting schedule with respect to particular restricted unit awards. The Committee amended the plan to make its vesting schedule comparable to those of similar plans offered by other companies. Unvested awards are subject to forfeiture in certain circumstances as defined in the applicable RUP document. Upon vesting, restricted units are automatically converted into our Common Units, with full voting rights and rights to receive distributions.

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

All RUP awards are approved by the Committee. Because individual circumstances differ, the Committee has not adopted a formulaic approach to making RUP awards. Although the reasons for granting an award can vary, the objective of granting an award to a recipient is to retain the services of the recipient over the ~~five-year~~ vesting period while, at the same time providing the type of motivation that further aligns the long-term interests of the recipient with the long-term interests of our Unitholders. The reasons for which the Committee grants RUP awards include, but are not limited to, the following:

In determining the quantity of restricted units to grant to executive officers and other key employees, the Committee considers, without limitation:

In addition, in establishing the level of restricted units to grant to our executive officers, the Committee considers the existing level of outstanding unvested RUP awards held by our executive officers.

The Committee generally approves awards under the RUP at its first meeting each fiscal year following the availability of the financial results for the prior fiscal year; however, occasionally the Committee grants awards at other times of the year, particularly when the need arises to grant awards because of promotions and new hires.

During fiscal ~~2012,~~2013, the Committee determined grants of RUP awards to the named executive officers would further align the interests of management with the interests of our Unitholders and approved the following grants to the named executive officers:

In determining the fiscal ~~2012~~2013 awards for ~~Mr. Dunn,~~ Mr. Stivala, Mr. Boyd, Mr. Wienberg and Mr. Brinkworth, the Committee relied upon information provided by the Mercer database to conclude that these awards were necessary to remediate shortfalls perceived by the Committee in the cash compensation opportunities of these named executive officers, as well as in recognition of their individual achievements. The Committee also took into consideration the increased responsibilities assumed by each of these named executive officers as a result of the Inergy Propane Acquisition. No award was granted to our Chief Executive Officer at the Committee’s meeting of November 13, 2012 because of the remaining unvested RUP awards that had been previously granted in connection with the execution of the letter agreement with Mr. Dunn. See section entitled “Letter Agreement of Mr. Dunn” below.

The aggregate grant date fair values of RUP awards made during fiscal 2013, fiscal 2012 and fiscal 2011, ~~and fiscal 2010,~~ computed in accordance with accounting principles generally accepted in the United States of America are reported in the column titled “Unit Awards” in the Summary Compensation Table below.

~~At its meeting on November 13, 2012, the Committee adopted a general policy with respect to the effective grant date of subsequent awards of restricted units under the RUP which states that:~~

Unless the Committee expressly determines otherwise for a particular award at the time of its approval of such award, the effective date of grant of all awards of restricted units under the RUP shall be the later of (i) November 15th of the calendar year in which the Committee approves an award, or (ii) the date on which the Committee approves the award. If, at the discretion of the Committee, an award is expressed as a dollar amount, then such award shall be converted into the number of restricted units, as of the effective date of grant, 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.

For fiscal ~~2013,~~2014, at its meeting on November 13, ~~2012,~~2013, the Committee granted the following RUP awards to our named executive ~~officers.~~officers:

No award was granted to our Chief Executive Officer at this meeting ~~as a result~~because of the level of remaining unvested RUP awards that were previously granted in connection with the execution of the letter agreement with Mr. Dunn. See section entitled “Letter Agreement of Mr. Dunn” below. Also at its meeting on November 13, 2012, the Committee amended the RUP, applicable to all then outstanding unvested awards and all future awards, to provide for the vesting of all unvested RUP awards, held by a participant on the date of his or her death, on the six month anniversary of the date of death.

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

As of the January 2, ~~2012~~2013 measurement date, all of our executive officers, including our named executive officers, were in compliance with Suburban’s Equity Holding Policy.

Upon recommendation by the Committee, the Board of Supervisors has adopted an Incentive Compensation Recoupment Policy which permits the Committee to seek the reimbursement from certain executives of Suburban and the Operating Partnership of incentive compensation (i.e., payments/awards pursuant to the annual cash bonus plan, the LTIP and RUP) paid to those executives in connection with any fiscal year for which there is a significant restatement of the published financial statements of Suburban triggered by a material accounting error, which results in less favorable results than those originally reported by Suburban. 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 Suburban 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 atwww.suburbanpropane.com under the “Investors” tab.

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

Each of our named executive officers, with the exception of Mr. Stivala and Mr. Wienberg, participates in the plan. The changes in the actuarial value relative to each named executive officer’s participation in the plan during fiscal 2013, fiscal 2012 and fiscal 2011 ~~and fiscal 2010~~ are reported in the column titled “Change in Pension Value and Nonqualified Deferred Compensation Earnings” in the Summary Compensation Table below.

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

For fiscal ~~2012,~~2013, 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 during fiscal 2013, fiscal 2012 and fiscal 2011 ~~and fiscal 2010~~ 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 ~~$250,000,~~$255,000, 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:

~~For fiscal 2012, our budgeted~~Actual cash bonus plan EBITDA, when applied to the 401(k) ~~Plan EBITDA~~plan, was $187.0 million. Because our fiscal 2012 results were less than the minimum needed to receive a 401(k) Plan match, we did not earn a match under the provisions of the Plan. However, because this is an element of compensationsuch that ~~has a widespread impact on all of our employees, the Compensation Committee provided a supplemental discretionary matching contribution of 20%. As a result,~~ we provided participants in the 401(k) plan with a ~~match~~matching contribution equal to ~~20%~~25% of their calendar year ~~2012~~2013 contributions that did not exceed 6% of their total base pay, up to a maximum annual compensation limit of ~~$250,000.~~$255,000. The matching contributions made on behalf of our named executive officers for ~~2012~~2013 are reported in the column titled “All Other Compensation” in the Summary Compensation Table below.

In 1998, we adopted a non-qualified, unfunded supplemental retirement plan known as the Suburban Propane Company Supplemental Executive Retirement Plan, which we refer to as the “SERP”. The purpose of the SERP was to provide certain of our executive officers with a level of retirement income from us, without regard to statutory maximums, including the IRC’s limitation for defined benefit plans. In light of the conversion of the Pension Plan to a cash balance formula as described under the subheading “Pension Plan” above, the SERP was amended and restated effective January 1, 1998. The annual retirement benefit under the SERP represents the amount of annual benefits that the participants in the SERP would otherwise be eligible to receive, calculated using the same pay-based credits referenced in the “Pension Plan” section above, applied to the amount of annual compensation that exceeds the IRC’s statutory maximums for defined benefit plans, which was $200,000 in 2002. Effective January 1, 2003, the SERP was discontinued with a frozen benefit determined for the remaining participants.

At the conclusion of fiscal 2010, Mr. Dunn was the only remaining participant in the SERP. Due to the actuarial costs and administrative burdens associated with maintaining this plan for one participant, at its November 9, 2010 meeting, the Committee terminated the SERP and paid Mr. Dunn his accrued benefit of $57,611 on December 1, 2010. Because Mr. Dunn received no above-market interest credits relative to the SERP during fiscal 2010, nothing related to Mr. Dunn’s participation in the SERP is reported in the Summary Compensation Table below.

As part of his total compensation package, each named executive officer is eligible to participate in all of our other employee benefit plans, such as the medical, dental, group life insurance and disability plans, on the same basis as other exempt employees. These benefit plans are offered to attract and retain talented employees by providing them with competitive benefits.

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

The costs of all such benefits incurred on behalf of our named executive officers in fiscal 2013, fiscal 2012 and fiscal 2011 ~~and fiscal 2010~~ are reported in the column titled “All Other Compensation” in the Summary Compensation Table below.

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 ~~2012.~~2013.


Name	Tax Preparation Services		Employer- Provided Vehicle		Physical		Tax Preparation Services		Employer- Provided Vehicle		Physical
Michael J. Dunn, Jr.	$	8,400	$	17,047	$	-0-	$	8,950	$	18,897	$	1,750
Michael A. Stivala	$	-0-	$	15,480	$	1,500	$	-0-	$	19,319	$	1,750
Steven C. Boyd	$	3,150	$	7,743	$	-0-	$	2,650	$	7,705	$	-0-
Mark Wienberg	$	-0-	$	11,676	$	1,500	$	-0-	$	13,570	$	1,500
Douglas T. Brinkworth	$	4,050	$	10,677	$	-0-	$	4,050	$	11,521	$	1,750

Perquisite-related costs for fiscal 2013, fiscal 2012 and fiscal 2011 ~~and fiscal 2010~~ are reported in the column titled “All Other Compensation” in the Summary Compensation Table below.

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

Although it is Suburban’s practice to comply with the statutory and regulatory provisions of IRC Section 409A, ~~on November 2, 2005, the Board of Supervisors approved an amendment to~~ the Suburban Propane, L.P. Severance Protection Plan for Key Employees, which we refer to as the “Severance Plan,” ~~to provide~~provides that if any payment under the Severance Plan subjects a participant to the 20% ~~federal excise~~additional 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.

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

~~Mr. Dunn has not retired and his employment has not been terminated.~~ We also agreed that if there iswas a termination of Mr. Dunn’s employment in connection with a succession plan, it would be deemed a retirement for the purposes of his benefits under the employee benefit plans in which he participates. Mr. Dunn also agreed to provide us with transition consultation services for a period not to exceed two years following his departure. We also agreed that Mr. Dunn ~~will~~would not be deemed to have retired or terminated his employment if he simply ~~relinquishes~~relinquished the title and responsibilities of President but ~~remains~~remained our Chief Executive Officer.

On November 14, 2013, we announced that, pursuant to a succession plan developed by Mr. Dunn and our Board of Supervisors, Mr. Dunn will relinquish the role of President on March 31, 2014, and will retire as our Chief Executive Officer effective September 27, 2014, the last day of our 2014 fiscal year. Accordingly, the retirement provisions of our letter agreement with Mr. Dunn will become effective on September 28, 2014, at which time Mr. Dunn will be age 65.

Also on November 14, 2013, we announced that Mr. Stivala will assume the role of our President on April 1, 2014. Mr. Stivala’s compensation in his new role has not yet been established.

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.

Our executive officers and other key employees have built Suburban 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, which we refer to as the “Severance Protection Plan”. During fiscal ~~2012,~~2013, our Severance Protection Plan covered all executive officers, including the named executive officers.

The Severance Protection Plan provides for severance payments of either 65 or 78 weeks of base salary and target cash bonuses for such officers and key employees if within one year following a change of control their employment is terminated by us or our successor or they resign for Good Reason (as defined in the Severance Protection Plan). All named executive officers who participate in the Severance Protection Plan are eligible for 78 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~~participants. Also, without regard to whether a participant’s employment is terminated, all outstanding, unvested LTIP awards will vest immediately as if the three-year measurement period for each outstanding award concluded on the date the change of control ~~occurred and our TRU was such that, in relation~~occurred. Under the provisions of the LTIP document, an amount equal to the ~~performance~~cash value of 125% of a participant’s unvested LTIP units plus a sum equal to 125% of a participant’s unvested LTIP units multiplied by an amount equal to the ~~other members~~cumulative, per-Common Unit distribution from the beginning of an unvested award’s three-year measurement period through the ~~peer group, it fell within~~date on which a change of control occurred would become payable to the ~~top quartile.~~participants.

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

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.

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 ~~2012.~~2013.

The following table sets forth certain information concerning the compensation of each named executive officer during the fiscal years ended September 28, 2013, September 29, 2012, and September 24, ~~2011, and September 25, 2010:~~2011:


Name and Principal Position	Year		Salary ($)⁽¹⁾		Bonus ($)		Unit Awards ($)⁽²⁾		Non-Equity Incentive Plan Compensation ($)⁽³⁾		Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)⁽⁴⁾		All Other Compensation ($)⁽⁵⁾		Total ($)		Year		Salary ($)⁽¹⁾		Bonus ($)		Unit Awards ($)⁽²⁾		Non-Equity Incentive Plan Compensation ($)⁽³⁾		Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)⁽⁴⁾		All Other Compensation ($)⁽⁵⁾		Total ($)
(a)	(b)		(c )		(d)		(e)		(g)		(h)		(i)		(j)		(b)		(c )		(d)		(e)		(g)		(h)		(i)		(j)
Michael J. Dunn, Jr. President and Chief Executive Officer		2012	$	475,000		—	$	521,058		—	$	22,308	$	49,280	$	1,067,646		2013	$	495,000		—	$	369,124	$	297,000		—	$	54,619	$	1,215,743
		2011	$	475,000		—	$	729,076	$	285,000	$	3,764	$	49,530	$	1,542,370		2012	$	475,000		—	$	521,058		—	$	22,308	$	49,280	$	1,067,646
		2010	$	475,000		—	$	768,484	$	475,000	$	31,661	$	49,330	$	1,799,475		2011	$	475,000		—	$	729,076	$	285,000	$	3,764	$	49,530	$	1,542,370

Michael A. Stivala Chief Financial Officer		2012	$	275,000		—	$	328,487		—		—	$	36,557	$	640,044		2013	$	300,000		—	$	376,313	$	144,000		—	$	42,073	$	862,386
		2011	$	275,000		—	$	357,103	$	132,000		—	$	35,010	$	799,113		2012	$	275,000		—	$	328,487				—	$	36,557	$	640,044
		2010	$	275,000		—	$	320,699	$	206,250		—	$	37,569	$	839,518		2011	$	275,000		—	$	357,103	$	132,000		—	$	35,010	$	799,113

Steven C. Boyd Vice President of Field Operations		2012	$	270,000		—	$	326,310		—	$	41,823	$	32,763	$	670,896		2013	$	290,000		—	$	370,348	$	139,200		—	$	33,416	$	832,964
		2011	$	270,000		—	$	354,615	$	129,600	$	15,257	$	37,095	$	806,567		2012	$	270,000		—	$	326,310		—	$	41,823	$	32,763	$	670,896
		2010	$	270,000		—	$	317,799	$	202,500	$	21,101	$	34,762	$	846,162		2011	$	270,000		—	$	354,615	$	129,600	$	15,257	$	37,095	$	806,567

Mark Wienberg Vice President of Operational Support and Analysis		2012	$	250,000		—	$	317,553		—		—	$	32,854	$	600,407		2013	$	280,000		—	$	364,382	$	134,400		—	$	36,055	$	814,837
		2011	$	250,000		—	$	344,653	$	120,000		—	$	33,725	$	748,378		2012	$	250,000		—	$	317,553		—		—	$	32,854	$	600,407
		2010	$	250,000		—	$	273,398	$	175,000		—	$	35,755	$	734,153		2011	$	250,000		—	$	344,653	$	120,000		—	$	33,725	$	748,378

Douglas T. Brinkworth Vice President of Product Supply		2012	$	245,000		—	$	315,326		—	$	24,327	$	35,786	$	620,439		2013	$	270,000		—	$	358,418	$	129,600		—	$	40,772	$	798,790
		2011	$	245,000		—	$	342,155	$	117,600	$	10,245	$	39,156	$	754,156		2012	$	245,000		—	$	315,326		—	$	24,327	$	35,786	$	620,439
		2010	$	245,000		—	$	303,237	$	183,750	$	12,959	$	41,767	$	786,713		2011	$	245,000		—	$	342,155	$	117,600	$	10,245	$	39,156	$	754,156

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

(2)

The amounts reported in this column represent the aggregate grant date fair value of RUP awards made during fiscal years 2013, 2012 ~~2011~~ and ~~2010,~~2011, as well as the value at the grant date of awards made in fiscal years 2013, 2012, ~~2011,~~ and ~~2010~~2011 under the LTIP, based on the probable outcome with respect to satisfaction of the performance conditions. The specific details regarding these plans are provided in the preceding “Compensation Discussion and Analysis” under the subheadings “Restricted Unit Plan” and “Long-Term Incentive Plan.” The breakdown for each plan with respect to each named executive officer is as follows:


Plan Name	Mr. Dunn		Mr. Stivala		Mr. Boyd		Mr. Wienberg		Mr. Brinkworth		Mr. Dunn		Mr. Stivala		Mr. Boyd		Mr. Wienberg		Mr. Brinkworth
2013
RUP												NA	$	197,351	$	197,351	$	197,351	$	197,351
LTIP												369,124		178,962		172,997		167,031		161,067

Total											$	369,124	$	376,313	$	370,348	$	364,382	$	358,418

2012
RUP	$	260,900	$	208,007	$	208,007	$	208,007	$	208,007	$	260,900	$	208,007	$	208,007	$	208,007	$	208,007
LTIP		260,158		120,480		118,303		109,546		107,319		260,158		120,480		118,303		109,546		107,319

Total	$	521,058	$	328,487	$	326,310	$	317,553	$	315,326	$	521,058	$	328,487	$	326,310	$	317,553	$	315,326

2011
RUP	$	433,249	$	220,090	$	220,090	$	220,090	$	220,090	$	433,249	$	220,090	$	220,090	$	220,090	$	220,090
LTIP		295,827		137,013		134,525		124,563		122,065		295,827		137,013		134,525		124,563		122,065

Total	$	729,076	$	357,103	$	354,615	$	344,653	$	342,155	$	729,076	$	357,103	$	354,615	$	344,653	$	342,155

2010
RUP	$	399,438	$	160,456	$	160,456	$	160,456	$	160,456
LTIP		369,046		160,243		157,343		112,942		142,781
Total	$	768,484	$	320,699	$	317,799	$	273,398	$	303,237


2013												2013
Type of Compensation													Mr. Dunn		Mr. Stivala		Mr. Boyd		Mr. Wienberg		Mr. Brinkworth
401(k) Match													$	3,825	$	3,825	$	3,825	$	3,825	$	3,825
Value of Annual Physical Examination														1,750		1,750		N/A		1,500		1,750
Value of Partnership Provided Vehicle														18,897		19,319		7,705		13,570		11,521
Tax Preparation Services														8,950		N/A		2,650		N/A		4,050
Cash Balance Plan Administrative Fees														1,500		N/A		1,500		N/A		1,500
Insurance Premiums														19,697		17,179		17,736		17,160		18,126

Totals													$	54,619	$	42,073	$	33,416	$	36,055	$	40,772


2012	2012											2012
Type of Compensation		Mr. Dunn		Mr. Stivala		Mr. Boyd		Mr. Wienberg		Mr. Brinkworth			Mr. Dunn		Mr. Stivala		Mr. Boyd		Mr. Wienberg		Mr. Brinkworth
401(k) Match		$	3,000	$	3,000	$	3,000	$	3,000	$	2,940		$	3,000	$	3,000	$	3,000	$	3,000	$	2,940
Value of Annual Physical Examination			N/A		1,500		N/A		1,500		N/A			N/A		1,500		N/A		1,500		N/A
Value of Partnership Provided Vehicle			17,047		15,480		7,743		11,676		10,677			17,047		15,480		7,743		11,676		10,677
Tax Preparation Services			8,400		N/A		3,150		N/A		4,050			8,400		N/A		3,150		N/A		4,050
Cash Balance Plan Administrative Fees			1,500		N/A		1,500		N/A		1,500			1,500		N/A		1,500		N/A		1,500
Insurance Premiums			19,333		16,577		17,370		16,678		16,619			19,333		16,577		17,370		16,678		16,619

Totals		$	49,280	$	36,557	$	32,763	$	32,854	$	35,786		$	49,280	$	36,557	$	32,763	$	32,854	$	35,786


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

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

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

The following table sets forth certain information concerning grants of awards made to each named executive officer during the fiscal year ended September ~~29, 2012:~~28, 2013:


							Estimated Future Payments Under Non-Equity Incentive Plan Awards				Estimated Future Payments Under Equity Incentive Plan Awards													Estimated Future Payments Under Non-Equity Incentive Plan Awards				Estimated Future Payments Under Equity Incentive Plan Awards
Name	Plan Name	Grant Date		Approval Date		Phantom Units Underlying Equity Incentive Plan Awards (LTIP)⁽⁴⁾	Target ($)		Maximum ($)		Target ($)		Maximum ($)		All Other stock Awards: Number of Shares of Stock or Units (#)	Grant Date Fair Value of Stock and Option Awards ($)⁽⁵⁾		Plan Name	Grant Date	Approval Date		LTIP Units Underlying Equity Incentive Plan Awards (LTIP)⁽⁴⁾		Target ($)		Maximum ($)		Target ($)		Maximum ($)		All Other stock Awards: Number of Shares of Stock or Units (#)		Grant Date Fair Value of Stock and Option Awards ($)⁽⁵⁾
(a)		(b)					(d)		(e)		(g)		(h)		(i)	(l)			(b)					(d)		(e)		(g)		(h)		(i)		(l)
Michael J. Dunn, Jr.	RUP⁽¹⁾		1 Dec 11		9 Nov 11										8,000	$	260,900	RUP ⁽¹⁾
	Bonus⁽²⁾		25 Sep 11				$	475,000	$	570,000								Bonus ⁽²⁾	30 Sep 12					$	495,000	$	594,000
	LTIP⁽³⁾		25 Sep 11			5,258					$	260,158	$	325,222				LTIP ⁽³⁾	30 Sep 12				6,559					$	369,124	$	461,405

Michael A. Stivala	RUP⁽¹⁾		1 Dec 11		9 Nov 11										6,378	$	208,007	RUP ⁽¹⁾	15 Nov 12		13 Nov 12												8,432	$	197,351
	Bonus⁽²⁾		25 Sep 11				$	220,000	$	264,000
	LTIP⁽³⁾		25 Sep 11			2,435					$	120,480	$	150,612				Bonus ⁽²⁾	30 Sep 12					$	240,000	$	288,000
																		LTIP ⁽³⁾	30 Sep 12				3,180					$	178,962	$	223,703
Steven C. Boyd	RUP⁽¹⁾		1 Dec 11		9 Nov 11										6,378	$	208,007	RUP ⁽¹⁾	15 Nov 12		13 Nov 12												8,432	$	197,351
	Bonus⁽²⁾		25 Sep 11				$	216,000	$	259,200								Bonus ⁽²⁾	30 Sep 12					$	232,000	$	278,400
	LTIP⁽³⁾		25 Sep 11			2,391					$	118,303	$	147,891				LTIP ⁽³⁾	30 Sep 12				3,074					$	172,997	$	216,246

Mark Wienberg	RUP⁽¹⁾		1 Dec 11		9 Nov 11										6,378	$	208,007	RUP ⁽¹⁾	15 Nov 12		13 Nov 12												8,432	$	197,351
	Bonus⁽²⁾		25 Sep 11				$	200,000	$	240,000								Bonus ⁽²⁾	30 Sep 12					$	224,000	$	268,800
	LTIP⁽³⁾		25 Sep 11			2,214					$	109,546	$	136,956				LTIP ⁽³⁾	30 Sep 12				2,968					$	167,031	$	208,789
Douglas T. Brinkworth																		RUP ⁽¹⁾	15 Nov 12		13 Nov 12												8,432	$	197,351
																		Bonus ⁽²⁾	30 Sep 12					$	216,000	$	259,200
Douglas T.	RUP⁽¹⁾		1 Dec 11		9 Nov 11										6,378	$	208,007
Brinkworth	Bonus⁽²⁾		25 Sep 11				$	196,000	$	235,200
	LTIP⁽³⁾		25 Sep 11			2,169					$	107,319	$	134,136				LTIP ⁽³⁾	30 Sep 12				2,862					$	161,067	$	201,334

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

The following table sets forth certain information concerning outstanding equity awards under our Restricted Unit Plan and ~~phantom equity~~LTIP unit awards under our LTIP for each named executive officer as of September ~~29, 2012:~~28, 2013:


Stock Awards	Stock Awards									Stock Awards
Name		Number of Shares or Units of Stock That Have Not Vested (#)⁽⁶⁾		Market Value of Shares or Units of Stock That Have Not Vested ($)⁽⁷⁾		Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights that Have Not Vested (#)⁽⁸⁾		Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($)⁽⁹⁾			Number of Shares or Units of Stock That Have Not Vested (#)⁽⁶⁾		Market Value of Shares or Units of Stock That Have Not Vested ($)⁽⁷⁾		Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights that Have Not Vested (#)⁽⁸⁾		Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($)⁽⁹⁾
(a)		(g)		(h)		(i)		(j)			(g)		(h)		(i)		(j)
Michael J. Dunn, Jr.⁽¹⁾			22,765	$	935,300		10,045	$	496,985			8,000	$	370,960		11,817	$	664,557
Michael A. Stivala⁽²⁾			21,670	$	890,312		4,652	$	230,162			26,484	$	1,228,063		5,615	$	315,779
Steven C. Boyd⁽³⁾			20,552	$	844,379		4,568	$	226,005			25,360	$	1,175,943		5,465	$	307,342
Mark Wienberg⁽⁴⁾			19,330	$	794,173		4,230	$	209,284			25,682	$	1,190,874		5,182	$	291,430
Douglas T. Brinkworth⁽⁵⁾			21,034	$	864,182		4,144	$	205,028			25,682	$	1,190,874		5,031	$	282,937


Vesting Date	Dec 3, 2012		Dec 1, 2014		Dec 1, 2015		Dec 1, 2016		Dec 1 2014		Dec 1 2015		Dec 1 2016
Quantity of Units		14,765		2,000		2,000		4,000		2,000		2,000		4,000


Vesting Date	Dec 1, 2012		Dec 3, 2012		Dec 1, 2013		Dec 1, 2014		Dec 1, 2015		Dec 1, 2016		Dec 1 2013		Dec 1 2014		Nov 15 2015		Dec 1 2015		Nov 15 2016		Dec 1 2016		Nov 15 2017
Quantity of Units		2,482		1,136		5,044		5,507		4,313		3,188		5,044		5,507		2,108		4,313		2,108		3,188		4,216


Vesting Date	Dec 1, 2012		Dec 3, 2012		Dec 1, 2013		Dec 1, 2014		Dec 1, 2015		Dec 1, 2016		Dec 1 2013		Dec 1 2014		Nov 15 2015		Dec 1 2015		Nov 15 2015		Dec 1 2016		Nov 15 2017
Quantity of Units		1,920		1,704		3,920		5,507		4,313		3,188		3,920		5,507		2,108		4,313		2,108		3,188		4,216


Vesting Date	Dec 1, 2012		Dec 1, 2013		Dec 1, 2014		Dec 1, 2015		Dec 1, 2016		Dec 1, 2013		Dec 1, 2014		Nov 15 2015		Dec 1, 2015		Nov 15 2016		Dec 1 2016		Nov 15 2017
Quantity of Units		2,080		4,292		5,557		4,213		3,188		4,292		5,557		2,108		4,213		2,108		3,188		4,216


Vesting Date	Dec 1, 2012		Dec 3, 2012		Dec 1, 2013		Dec 1, 2014		Dec 1, 2015		Dec 1, 2016		Dec 1, 2013		Dec 1, 2014		Nov 15 2015		Dec 1, 2015		Nov 15 2016		Dec 1 2016		Nov 15 2017
Quantity of Units		2,080		1,704		4,242		5,507		4,313		3,188		4,242		5,507		2,108		4,313		2,108		3,188		4,216

(9)

The amounts reported in this column represent the estimated future target payouts of the fiscal ~~2012~~2013 and fiscal ~~2011~~2012 awards granted under the LTIP. These amounts were computed by multiplying the quantities of the unvested ~~phantom~~LTIP units in column (i) by the average of the closing prices of our Common Units for the twenty business days preceding September ~~29, 2012~~28, 2013 (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~~LTIP 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:

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.

Awards under the Restricted Unit Plans are settled in Common Units upon vesting. Awards under the LTIP, a ~~phantom-equity~~LTIP-equity plan, are settled in cash. The following two tables set forth certain information concerning the vesting of awards under our Restricted Unit ~~Plan~~Plans and the vesting of the fiscal ~~2010~~2011 award under our LTIP for each named executive officer during the fiscal year ended September ~~29, 2012:~~28, 2013:


Restricted Unit Plans	Unit Awards			Unit Awards
				Number of Common Units		Value Realized
Name	Number of Common Units Acquired on Vesting (#)	Value Realized on Vesting ($) ⁽¹⁾		Acquired on Vesting (#)		on Vesting ($) ⁽¹⁾
Michael J. Dunn, Jr.	27,792	$	1,185,806		14,765	$	595,842
Michael A. Stivala	4,521	$	203,435		3,618	$	146,004
Steven C. Boyd	4,243	$	190,358		3,624	$	146,247
Mark Wienberg	3,551	$	157,806		2,080	$	83,938
Douglas T. Brinkworth	2,748	$	113,800		3,784	$	152,703


Long-Term Incentive Plan – Fiscal 2010⁽²⁾ Award	Cash Awards
Long-Term Incentive Plan – Fiscal 2011⁽²⁾ Award				Cash Awards
				Number of LTIP Units		Value Realized
Name	Number of Phantom Units Acquired on Vesting (#) ⁽³⁾	Value Realized on Vesting ($) ⁽⁴⁾		Acquired on Vesting (#) ⁽³⁾		on Vesting ($) ⁽⁴⁾
Michael J. Dunn, Jr.	5,981	$	0		4,787	$	0
Michael A. Stivala	2,597	$	0		2,217	$	0
Steven C. Boyd	2,550	$	0		2,177	$	0
Mark Wienberg	2,203	$	0		2,016	$	0
Douglas T. Brinkworth	2,314	$	0		1,975	$	0

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 ~~29, 2012:~~28, 2013:


Name	Plan Name	Number of Years Credited Service (#)		Present Value of Accumulated Benefit ($)		Payments During Last Fiscal Year ($)		Plan Name	Number of Years Credited Service (#)	Present Value of Accumulated Benefit ($)		Payments During Last Fiscal Year ($)
Michael J. Dunn, Jr.	Cash Balance Plan⁽¹⁾		6	$	272,430	$	—	Cash Balance Plan⁽¹⁾	6	$	247,290	$	—
	LTIP⁽³⁾		N/A	$	496,985	$	—	LTIP⁽³⁾	N/A	$	664,557	$	—
	RUP⁽⁴⁾		N/A	$	935,300	$	—	RUP⁽⁴⁾	N/A	$	370,960	$	—

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

Steven C. Boyd	Cash Balance Plan ⁽¹⁾		15	$	198,503	$	—	Cash Balance Plan ⁽¹⁾	15	$	169,912	$	—

Mark Wienberg⁽²⁾	N/A		N/A	$	—	$	—	N/A	N/A	$	—	$	—

Douglas T. Brinkworth	Cash Balance Plan ⁽¹⁾		6	$	123,247	$	—	Cash Balance Plan ⁽¹⁾	6	$	108,504	$	—

The following table sets forth certain information containing potential payments to the named executive officers in accordance with the provisions of Mr. Dunn’s letter agreement, the Severance Protection Plan, the RUP and the LTIP for the circumstances listed in the table assuming a September ~~29, 2012~~28, 2013 termination date. For more information on Mr. Dunn’s letter agreement, refer to the subheading “Letter Agreement of ~~Mt. Dun”~~Mr. Dunn” in the “Compensation Discussion and Analysis.”


Executive Payments and Benefits Upon Termination	Death		Disability		Involuntary Termination Without Cause by Suburban or by the Executive for Good Reason without a Change of Control Event		Involuntary Termination Without Cause by Suburban or by the Executive for Good Reason with a Change of Control Event		Death		Disability		Involuntary Termination Without Cause by Suburban or by the Executive for Good Reason without a Change of Control Event		Involuntary Termination Without Cause by Suburban or by the Executive for Good Reason with a Change of Control Event
Michael J. Dunn, Jr.
Cash Compensation^{(1) (2) (3) (4)}	$	-0-	$	950,000	$	950,000	$	1,425,000	$	-0-	$	990,000	$	990,000	$	1,485,000
Accelerated Vesting of Fiscal 2012 and 2011 LTIP Awards⁽⁵⁾		N/A		N/A		N/A		621,268
Accelerated Vesting of Fiscal 2013, 2012, and 2011 LTIP Awards⁽⁵⁾										N/A		N/A		N/A		1,118,988
Accelerated Vesting of Outstanding RUP Awards⁽⁶⁾		N/A		935,300		935,300		935,300		370,960		370,960		370,960		370,960
Medical Benefits⁽³⁾		N/A		28,100		28,100		N/A		N/A		16,414		16,414		N/A

Total	$	-0-	$	1,913,400	$	1,913,400	$	2,981,568	$	370,960	$	1,377,374	$	1,377,374	$	2,974,948


Michael A. Stivala
Cash Compensation^{(1) (2) (3) (4)}	$	-0-	$	-0-	$	275,000	$	742,500	$	-0-	$	-0-	$	300,000	$	810,000
Accelerated Vesting of Fiscal 2012 and 2011 LTIP Awards⁽⁵⁾		N/A		N/A		N/A		287,702
Accelerated Vesting of Fiscal 2013, 2012, and 2011 LTIP Awards⁽⁵⁾										N/A		N/A		N/A		526,985
Accelerated Vesting of Outstanding RUP Awards⁽⁶⁾		N/A		628,272		N/A		890,312		1,228,063		837,071		N/A		1,228,063
Medical Benefits⁽³⁾		N/A		N/A		13,221		N/A		N/A		N/A		17,179		N/A

Total	$	-0-	$	628,272	$	288,221	$	1,920,514	$	1,228,063	$	837,071	$	317,179	$	2,565,048


Steven C. Boyd
Cash Compensation^{(1) (2) (3) (4)}	$	-0-	$	-0-	$	270,000	$	729,000	$	-0-	$	-0-	$	290,000	$	783,000
Accelerated Vesting of Fiscal 2012 and 2011 LTIP Awards⁽⁵⁾		N/A		N/A		N/A		282,507
Accelerated Vesting of Fiscal 2013, 2012, and 2011 LTIP Awards⁽⁵⁾										N/A		N/A		N/A		514,473
Accelerated Vesting of Outstanding RUP Awards⁽⁶⁾		N/A		582,339		N/A		844,379		1,175,943		784,951		N/A		1,175,943
Medical Benefits⁽³⁾		N/A		N/A		13,677		N/A		N/A		N/A		17,736		N/A

Total	$	-0-	$	582,339	$	283,677	$	1,855,886	$	1,175,943	$	784,951	$	307,736	$	2,473,416


Mark Wienberg
Cash Compensation^{(1) (2) (3) (4)}	$	-0-	$	-0-	$	250,000	$	675,000	$	-0-	$	-0-	$	280,000	$	756,000
Accelerated Vesting of Fiscal 2012 and 2011 LTIP Awards⁽⁵⁾		N/A		N/A		N/A		261,628
Accelerated Vesting of Fiscal 2013, 2012, and 2011 LTIP Awards⁽⁵⁾										N/A		N/A		N/A		483,876
Accelerated Vesting of Outstanding RUP Awards⁽⁶⁾		N/A		532,133		N/A		794,173		1,190,874		799,883		N/A		1,190,874
Medical Benefits⁽³⁾		N/A		N/A		13,221		N/A		N/A		N/A		17,159		N/A

Total	$	-0-	$	532,133	$	263,221	$	1,730,801	$	1,190,874	$	799,883	$	297,159	$	2,430,750


Douglas T. Brinkworth
Cash Compensation^{(1) (2) (3) (4)}	$	-0-	$	-0-	$	245,000	$	661,500	$	-0-	$	-0-	$	270,000	$	729,000
Accelerated Vesting of Fiscal 2012 and 2011 LTIP Awards⁽⁵⁾		N/A		N/A		N/A		256,285
Accelerated Vesting of Fiscal 2013, 2012, and 2011 LTIP Awards⁽⁵⁾										N/A		N/A		N/A		471,227
Accelerated Vesting of Outstanding RUP Awards⁽⁶⁾		N/A		602,142		N/A		864,182		1,190,874		799,883		N/A		1,190,874
Medical Benefits⁽³⁾		N/A		N/A		13,221		N/A		N/A		N/A		18,126		N/A

Total	$	-0-	$	602,142	$	258,221	$	1,781,967	$	1,190,874	$	799,883	$	288,126	$	2,391,101

(4)

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

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 Suburban and will be subject to the same risks as awards held by all other participants.

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.

The following table sets forth the compensation of the non-employee members of the Board of Supervisors of Suburban during fiscal ~~2012.~~2013.


Supervisor	Fees Earned or Paid in Cash ($)⁽¹⁾		Unit Awards ($)⁽²⁾		Total ($)		Fees Earned or Paid in Cash ($)⁽¹⁾		Unit Awards ($)⁽²⁾		Total ($)
Harold R. Logan, Jr.								115,000		140,430		255,430
Lawrence C. Caldwell								85,000		140,791		225,791
Matthew J. Chanin								85,000		140,791		225,791
John D. Collins		75,000		-0-		75,000		85,000		140,430		225,430
Harold R. Logan, Jr.		100,000		-0-		100,000
Dudley C. Mecum		75,000		-0-		75,000		85,000		140,430		225,430
John Hoyt Stookey		75,000		-0-		75,000		85,000		140,430		225,430
Jane Swift		75,000		-0-		75,000		85,000		140,430		225,430

Annual Cash Retainer Fees. As the Chairman of the Board of Supervisors, Mr. Logan received an annual retainer of ~~$100,000~~$115,000 in fiscal ~~2012,~~2013, payable in quarterly installments of ~~$25,000~~$28,750 each. Each of the other non-employee Supervisors received an annual cash retainer of ~~$75,000~~$85,000 in fiscal ~~2012,~~2013, payable in quarterly installments of ~~$18,750~~$21,250 each.

At its meeting on November 13, 2012, the Committee increased Mr. Logan’s annual retainer to $115,000, payable in quarterly installments of $28,750 each. Each of the other Supervisors’ annual retainers was increased to $85,000, payable in quarterly installments of $21,250. The effective date of the increases is January 1, 2013.

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

Restricted Unit Plans. Each non-employee Supervisor participates in the Restricted Unit Plans. All awards vest in accordance with the provisions of the plan document (see “Compensation Discussion and Analysis” section titled “Restricted Unit Plans” for a description of the vesting schedule). Upon vesting, all awards are settled by issuing Common Units. During fiscal 2004, Messrs. Logan, Mecum and Stookey were granted unvested restricted unit plan awards of 8,500 units each; during fiscal 2007, each of them received an additional unvested award of 3,000 units. Upon commencement of their terms as Supervisors in fiscal 2007, Mr. Collins and Ms. Swift each received an award of 5,496 units. During fiscal 2010, each non-employee Supervisor received an award of 3,600 units. On September 29, 2012, the only unvested unit awards held by each non-employee Supervisors were the fiscal 2010 grants of 3,600 units.

At its meeting on November 13, 2012, the Committee granted Messrs. Caldwell and Chanin unvested RUP awards of 6,023 ~~(based on a value of $250,000 on the effective date of grant)~~ each in recognition of the commencement of their terms as Supervisors on November 13, 2012. The Committee also granted Messrs. Logan, Collins, Mecum, and Stookey and Ms. Swift additional unvested RUP awards of 6,000 each in recognition of their continued service to the Partnership. The effective date of these grants is November 15, 2012.

Messrs. Logan, Mecum and Stookey are the only non-employee Supervisors who have satisfied the retirement provisions of Suburban’s Restricted Unit Plans. As of September 28, 2013, Messrs. Logan, Collins, Mecum, Stookey, and Ms. Swift each held awards of 8,700 unvested restricted units and Messrs. Caldwell and Chanin each held awards of 6,023 unvested restricted 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 ~~2012~~2013 for each Supervisor.

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS

The following table sets forth certain information as of November ~~26, 2012~~25, 2013 regarding the beneficial ownership of Common Units by (a) each person or group known to the Partnership, based upon its review of filings under Section 13(d) or (g) under the Securities Act, to own more than 5% of the outstanding Common Units; (b) each member of the Board of ~~Supervisors,~~Supervisors; (c) each executive officer named in the Summary Compensation Table in Item 11 of this Annual ~~Report,~~Report; and (d) 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.

(b)	Includes 784 Common Units held by the General Partner, of which Mr. Dunn is the sole member. Excludes 8,000 unvested restricted units, none of which will vest in the 60-day period following November ~~26, 2012.~~25, 2013.

~~(f)~~(g)

Excludes ~~9,600~~8,700 unvested restricted units, none of which will vest in the 60-day period following November ~~26, 2012.~~25, 2013.

The following table sets forth certain information, as of September ~~29, 2012,~~28, 2013, 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.


Plan Category	Number of Common Units to be issued upon vesting of restricted units (a)			Weighted-average grant date fair value per restricted unit (b)		Number of restricted units remaining available for future issuance under the Restricted Unit Plans (excluding securities reflected in column (a)) (c)		Number of Common Units to be issued upon vesting of restricted units (a)			Weighted- average grant date fair value per restricted unit (b)		Number of restricted units remaining available for future issuance under the Restricted Unit Plans (excluding securities reflected in column (a)) (c)
Equity compensation plans approved by security holders (1)		442,851	(2)	$	32.68		869,198		527,627	(2)	$	29.30		668,860
Equity compensation plans not approved by security holders		—			—		—		—			—		—

Total		442,851		$	32.68		869,198		527,627		$	29.30		668,860

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR 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:

A copy of our Corporate Governance Guidelines is available without charge from our website atwww.suburbanpropane.com or upon written request directed to: Suburban Propane Partners, L.P., Investor Relations, P.O. Box 206, Whippany, New Jersey 07981-0206.

The following table sets forth the aggregate fees for services related to fiscal years ~~2012~~2013 and ~~2011~~2012 provided by PricewaterhouseCoopers LLP, our independent registered public accounting firm.


	Fiscal		Fiscal		Fiscal		Fiscal
	2012		2011		2013		2012
Audit Fees (a)	$	3,633,000	$	1,956,000	$	2,378,400	$	3,633,000
Audit-Related Fees (b)		450,000		—		—		450,000
Tax Fees (c)		884,152		686,425		1,399,000		884,152
All Other Fees (d)		1,800		1,800		1,800		1,800

	$	4,968,952	$	2,644,225	$	3,779,200	$	4,968,952

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 ~~2012~~2013 and fiscal ~~2011.~~2012.

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

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

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.



~~4.8~~ 4.5		Support Agreement, dated as of August 1, 2012, among Inergy, L.P., the Partnership and Suburban Energy Finance Corp. (Incorporated by reference to Exhibit 4.3 to the Partnership’s Registration Statement on Form S-4 dated September 19, 2012.



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

10.2		Suburban Propane Partners, L.P. 2000 Restricted Unit Plan, as amended and restated effective October 17, 2006 and as further amended on July 31, 2007, October 31, 2007, January 24, 2008, January 20, 2009, November 10, 2009 and November 13, 2012. (Incorporated by reference to Exhibit 99.1 to the Partnership’s Current Report on Form 8-K filed November 14, 2012).

10.3		Suburban Propane Partners, L.P. 2009 Restricted Unit Plan, effective August 1, 2009, as amended on November 13, ~~2012.~~2012 and August 6, 2013. (Incorporated by reference to Exhibit 99.2 to the Partnership’s Current Report on Form 8-K filed ~~November 14, 2012)~~August 7, 2013).

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

10.5		Suburban Propane L.P. 2003 Long Term Incentive Plan, as amended on October 17, 2006 and as further amended on July 31, 2007, October 31, 2007, January 24, 2008 and January 20, 2009. (Incorporated by reference to Exhibit 10.3 to the Partnership’s Quarterly Report on Form 10-Q for the fiscal quarter ended December 27, 2008).

10.6		Suburban Propane, L.P. 2013 Long Term Incentive Plan. (Incorporated by reference to Exhibit 99.1 to the Partnership’s Current Report on Form 8-K filed November 10, 2011).

10.7		Suburban Propane, L.P. 2014 Long Term Incentive Plan. (Incorporated by reference to Exhibit 99.1 to the Partnership’s Current Report on Form 8-K filed August 7, 2013).

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

~~10.8~~ 10.9		Amendment No. 1 to the Retirement Savings and Investment Plan of Suburban Propane (effective January 1, 2002). (Incorporated by reference to Exhibit 10.25 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 28, 2002).

~~10.9~~ 10.10		Amended and Restated Credit Agreement, among the Operating Partnership, the Partnership and Bank of America, N.A., as Administrative Agent and the Lenders party thereto, dated January 5, 2012. (Incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed on January 6, 2012).

~~10.10~~ 10.11		First Amendment to the Amended and Restated Credit Agreement, among the Operating Partnership, the Partnership and Bank of America, N.A., as Administrative Agent, and the Lenders party thereto, dated August 1, 2012. (Incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed on August 2, 2012).

~~10.11~~ 10.12		Propane Storage Agreement, dated September 17, 2007, between Suburban Propane, L.P. and Plains LPG Services, L.P. (Incorporated by reference to Exhibit 10.3 to the Partnership’s Current Report on Form 8-K filed September 20, 2007).

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

23.1		Consent of PricewaterhouseCoopers LLP. (Filed herewith).



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

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

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

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

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

101.INS		XBRL Instance Document

101.SCH		XBRL Taxonomy Extension Schema Document

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

101.LAB		XBRL Taxonomy Extension Label Linkbase Document

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, partners’ capital, comprehensive income and cash flows present fairly, in all material respects, the financial position of Suburban Propane Partners, L.P. and its subsidiaries at September ~~29, 2012~~28, 2013 and September ~~24, 2011,~~29, 2012, and the results of their operations and their cash flows for each of the three fiscal years in the period ended September ~~29, 2012,~~28, 2013, 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 appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of September ~~29, 2012,~~28, 2013, based on criteria established inInternal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The ~~Partnership's~~Partnership’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in ~~Management's~~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~~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.

As described in Management’s Report on Internal Control over Financial Reporting, management has excluded Inergy Propane from its assessment of internal control over financial reporting as of September 29, 2012 because it was acquired by the Partnership in a business combination on August 1, 2012. We have also excluded Inergy Propane from our audit of internal control over financial reporting. Inergy Propane is wholly-owned by the Partnership and its total assets and total revenues represent 25% and 7%, respectively, of the related consolidated financial statement amounts as of and for the fiscal year ended September 29, 2012.


	September 29,			September 24,			September 28,			September 29,
	2012			2011			2013			2012
ASSETS
Current assets:
Cash and cash equivalents	$	134,317		$	149,553		$	107,232		$	134,317
Accounts receivable, less allowance for doubtful accounts of $4,347 and $6,960, respectively		88,944			66,630
Accounts receivable, less allowance for doubtful accounts of $6,786 and $4,347, respectively								94,854			88,944
Inventories		88,176			65,907			77,623			88,176
Other current assets		26,843			15,732			13,613			26,078

Total current assets		338,280			297,822			293,322			337,515
Property, plant and equipment, net		969,325			338,125			888,232			936,228
Goodwill		1,092,299			277,651			1,087,429			1,087,429
Other intangible assets, net		436,484			16,078			416,771			474,618
Other assets		48,060			26,783			42,233			48,060

Total assets	$	2,884,448		$	956,459		$	2,727,987		$	2,883,850

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	53,141		$	37,456		$	52,766		$	53,141
Accrued employment and benefit costs		16,514			22,951			23,559			16,514
Accrued insurance		8,591			9,950			6,650			8,591
Customer deposits and advances		124,297			57,476			107,562			124,297
Accrued interest								24,357			13,219
Other current liabilities		51,172			23,681			19,000			37,953

Total current liabilities		253,715			151,514			233,894			253,715
Long-term borrowings		1,422,078			348,169			1,245,237			1,422,078
Accrued insurance		45,960			42,891			51,502			45,960
Other liabilities		70,952			55,667			68,228			71,598

Total liabilities		1,792,705			598,241			1,598,861			1,793,351

Commitments and contingencies

Partners’ capital:
Common Unitholders (57,013 and 35,429 units issued and outstanding at September 29, 2012 and September 24, 2011, respectively)		1,152,850			418,134
Common Unitholders 60,231 and 57,013 units issued and outstanding at September 28, 2013 and September 29, 2012, respectively)								1,176,479			1,151,606
Accumulated other comprehensive loss		(61,107	)		(59,916	)		(47,353	)		(61,107	)

Total partners’ capital		1,091,743			358,218			1,129,126			1,090,499

Total liabilities and partners' capital	$	2,884,448		$	956,459
Total liabilities and partners’ capital							$	2,727,987		$	2,883,850

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


	Year Ended									Year Ended
	September			September			September			September			September			September
	29, 2012			24, 2011			25, 2010			28, 2013			29, 2012			24, 2011
Revenues
Propane	$	843,648		$	929,492		$	885,459		$	1,357,102		$	843,648		$	929,492
Fuel oil and refined fuels		114,288			139,572			135,059			208,957			114,288			139,572
Natural gas and electricity		67,419			84,721			77,587			79,432			67,419			84,721
All other		38,103			36,767			38,589			58,115			38,103			36,767

		1,063,458			1,190,552			1,136,694			1,703,606			1,063,458			1,190,552

Costs and expenses
Cost of products sold		599,059			678,719			598,451			861,905			599,059			678,719
Operating		298,772			279,329			289,567			469,496			298,772			281,329
General and administrative		59,020			51,648			61,656			64,845			59,020			51,648
Acquisition-related costs		17,916			—			—			—			17,916			—
Severance charge		—			2,000			—
Pension settlement charge		—			—			2,818
Depreciation and amortization		45,790			35,628			30,834			130,384			47,034			35,628

											1,526,630			1,021,801			1,047,324
		1,020,557			1,047,324			983,326

Operating income		42,901			143,228			153,368			176,976			41,657			143,228
Loss on debt extinguishment		(2,249	)		—			(9,473	)		(2,144	)		(2,249	)		—
Interest income		10			16			61
Interest expense		(38,643	)		(27,394	)		(27,458	)		(95,427	)		(38,633	)		(27,378	)


Income before provision for income taxes		2,019			115,850			116,498			79,405			775			115,850
Provision for income taxes		137			884			1,182			607			137			884


Net income	$	1,882		$	114,966		$	115,316		$	78,798		$	638		$	114,966


Income per Common Unit—basic	$	0.05		$	3.24		$	3.26		$	1.35		$	0.02		$	3.24

Weighted average number of Common Units outstanding—basic		38,848			35,525			35,374			58,378			38,848			35,525


Income per Common Unit—diluted	$	0.05		$	3.22		$	3.24		$	1.34		$	0.02		$	3.22

Weighted average number of Common Units outstanding—diluted		38,990			35,723			35,613			58,600			38,990			35,723

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

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 ~~57,013,232~~60,230,892 Common Units outstanding at September ~~29, 2012.~~28, 2013. 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”), as amended. Rights and privileges under the Partnership Agreement include, among other things, the election of all members of the Board of Supervisors and voting on the removal of the general partner.

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

The general partner of both the Partnership and the Operating Partnership is Suburban Energy Services Group LLC (the “General Partner”), a Delaware limited liability company, the sole member of which is the Partnership’s Chief Executive Officer. Other than as a holder of 784 Common Units that will remain in the General Partner, the General Partner does not have any economic interest in the Partnership or the Operating Partnership.

The Partnership’s fuel oil and refined fuels, natural gas and electricity and services businesses are structured as either limited liability companies that are treated as corporations or corporate entities (collectively referred to as the “Corporate Entities”) and, as such, are subject to corporate level U.S. income tax.

On August 1, 2012 (the “Acquisition Date”), the Partnership completed the acquisition of the sole membership interest in Inergy Propane, LLC, including certain wholly-owned subsidiaries of Inergy Propane LLC, and the assets of Inergy Sales and Service, Inc. The acquired interests and assets are collectively referred to as “Inergy Propane.” As of the Acquisition Date, Inergy Propane consisted of the former retail propane assets and operations of Inergy, L.P. (“Inergy”). On the Acquisition Date, Inergy Propane and its remaining wholly-owned subsidiaries acquired became subsidiaries of the Operating ~~Partnership.~~Partnership, but were merged into the Operating Partnership on April 30, 2013. The results of operations of Inergy Propane are included in the Partnership’s results of operations beginning on the Acquisition Date. See Note 3.

The Partnership serves more than 1,200,000 residential, commercial, industrial and agricultural customers from approximately 750 locations in 41 states. The Partnership’s operations are concentrated in the east and west coast regions, including Alaska, and have expanded into the mid-west region of the United States as a result of the acquisition of Inergy Propane. No single customer accounted for 10% or more of the Partnership’s revenues during fiscal 2013, 2012 ~~2011~~ or ~~2010.~~2011.

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 intercompany transactions and account balances have been eliminated. The Partnership consolidates the results of operations, financial condition and cash flows of the Operating Partnership as a result of the Partnership’s 100% limited partner interest in the Operating Partnership.

Fiscal Period. The Partnership uses a 52/53 week fiscal year which ends on the last Saturday in September. The Partnership’s fiscal quarters are generally 13 weeks in duration. When the Partnership’s fiscal year is 53 weeks long, the corresponding fourth quarter is 14 weeks in duration. Fiscal 2013 and fiscal 2011 included 52 weeks of operations and fiscal 2012 included 53 weeks of ~~operations compared to 52 weeks in fiscal 2011 and fiscal 2010.~~operations.

Revenue Recognition.Sales of propane, fuel oil and refined fuels are recognized at the time product is delivered to the customer. Revenue from the sale of appliances and equipment is recognized at the time of sale or when installation is complete, as applicable. Revenue from repairs, maintenance and other service activities is recognized upon completion of the service. Revenue from service contracts is recognized ratably over the service period. Revenue from the natural gas and electricity business is recognized based on customer usage as determined by meter readings for amounts delivered, some of which may be unbilled at the end of each accounting period. Revenue from annually billed tank fees is deferred at the time of billings and recognized on a straight-line basis over one year.

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

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

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

Use of Estimates.The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“US GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates have been made by management in the areas of self-insurance and litigation reserves, pension and other postretirement benefit liabilities and costs, valuation of derivative instruments, depreciation and amortization of long-lived assets, asset impairment assessments, tax valuation allowances, allowances for doubtful accounts, and purchase price allocation for acquired businesses. 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.

Commodity Price Risk. Given the retail nature of its operations, the Partnership maintains a certain level of priced physical inventory to ensure its field operations have adequate supply commensurate with the time of year. The Partnership’s strategy is to keep its physical inventory priced relatively close to market for its field operations. The Partnership enters into a combination of exchange-traded futures and option contracts and, in certain instances, over-the-counter options and swap contracts (collectively, “derivative instruments”) to hedge price risk associated with propane and fuel oil physical inventories, as well as future purchases of propane or fuel oil used in its operations and to ensure adequate supply during periods of high demand. In addition, the Partnership sells propane and fuel oil to customers at fixed prices, and enters into ~~swap agreements~~derivative instruments to hedge a portion of its exposure to fluctuations in commodity prices as a result of selling the fixed price contracts. 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 or delivered as it pertains to fixed price contracts. 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, forward and swap contracts~~derivative instruments 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 derivative instruments are entered into, other than those designated as normal purchases or normal sales, the Partnership makes a determination as to whether the derivative instrument qualifies for designation as a hedge. Changes in the fair value of derivative instruments are recorded each period in current period earnings or other comprehensive income (“OCI”), depending on whether the derivative instrument is designated as a hedge and, if so, the type of hedge. For derivative instruments designated as cash flow hedges, the Partnership formally assesses, both at the hedge contract’s inception and on an ongoing basis, whether the hedge contract is highly effective in offsetting changes in cash flows of hedged items. Changes in the fair value of derivative instruments designated as cash flow hedges are reported in OCI to the extent effective and reclassified into earnings during the same period in which the hedged item affects earnings. The mark-to-market gains or losses on ineffective portions of cash flow hedges are recognized in earnings immediately. Changes in the fair value of derivative instruments that are not designated as cash flow hedges, and that do not meet the normal purchase and normal sale exemption, are recorded within earnings as they occur. Cash flows associated with derivative instruments are reported as operating activities within the consolidated statement of cash flows.

Interest Rate Risk. A portion of the Partnership’s borrowings bear interest at prevailing interest rates based upon, at the Operating Partnership’s option, LIBOR plus an applicable margin or the base rate, defined as the higher of the Federal Funds Rate plus¹/⁄₂ of 1% or the agent bank’s prime rate, or LIBOR plus 1%, plus the applicable margin. The applicable margin is dependent on the level of the Partnership’s total leverage (the ratio of total debt to income before deducting interest expense, income taxes, depreciation and amortization (“EBITDA”)). Therefore, the Partnership is subject to interest rate risk on the variable component of the interest rate. The Partnership manages part of its variable interest rate risk by entering into interest rate swap agreements. The interest rate swaps have been designated as, and are accounted for as, cash flow hedges. The fair value of the interest rate swaps are determined using an income approach, whereby future settlements under the swaps are converted into a single present value, with fair value being based on the value of current market expectations about those future amounts. Changes in the fair value are recognized in OCI until the hedged item is recognized in earnings. However, due to changes in the underlying interest rate environment, the corresponding value in OCI is subject to change prior to its impact on earnings.

Valuation of Derivative Instruments. The Partnership measures the fair value of its exchange-traded options and futures contracts using quoted market prices found on the New York Mercantile Exchange (the “NYMEX”) (Level 1 inputs); the fair value of its swap ~~agreements~~contracts using quoted forward prices, and the fair value of its interest rate swaps using model-derived valuations driven by observable projected movements of the 3-month LIBOR (Level 2 inputs); and the fair value of its over-the-counter options contracts using Level 3 inputs. The Partnership’s over-the-counter options contracts are valued based on an internal option model. The inputs utilized in the model are based on publicly available information, as well as broker quotes. The significant unobservable inputs used in the fair value measurements of the Partnership’s over-the-counter options contracts are interest rate and market volatility.

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 thestraight-line method based upon the estimated useful life of the asset as follows:

The weighted average estimated useful life of the Partnership’s tanks and cylinders is approximately 28 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 as of the end of fiscal July of each year, or when an event occurs or circumstances change that would indicate potential impairment. ~~The~~

During the first quarter of fiscal 2013, the Partnership adopted new accounting guidance related to goodwill impairment testing. Under the new guidance, an entity has the option to first assess qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If, after assessing the totality of events or circumstances, an entity determines it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, then performing the two-step impairment test is unnecessary. However, if an entity concludes otherwise, then it is required to perform the first step of the two-step impairment test.

Under the two-step impairment test, the Partnership assesses the carrying value of goodwill at a reporting unit level based on an estimate of the fair value of the respective reporting unit. Fair value of the reporting unit is estimated using discounted cash flow analyses taking into consideration estimated cash flows in a ten-year projection period and a terminal value calculation at the end of the projection period. If the fair value of the reporting unit exceeds its carrying value, the goodwill associated with the reporting unit is not considered to be impaired. If the carrying value of the reporting unit exceeds its fair value, an impairment loss is recognized to the extent that the carrying amount of the associated goodwill, if any, exceeds the implied fair value of the goodwill.

Other Intangible Assets. Other intangible assets consist of customer relationships, tradenames, non-compete agreements and leasehold interests. Customer relationships 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 2014 and ~~2024.~~2021. Non-compete agreements are amortized under the straight-line method over the periods of the related agreements. Leasehold interests are amortized under the straight-line method over the shorter of the lease term or the useful life of the related assets, through fiscal 2025.

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

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

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

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

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

Asset Retirement Obligations.Asset retirement obligations apply to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of a long-lived asset. The Partnership has recognized asset retirement obligations for certain costs to remove and properly dispose of underground and aboveground fuel oil storage tanks and contractually mandated removal of leasehold improvements.

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

Unit-Based Compensation. The Partnership recognizes compensation cost over the respective service period for employee services received in exchange for an award of equity or equity-based compensation based on the grant date fair value of the award. The Partnership measures liability awards under an equity-based payment arrangement based on remeasurement of the award’s fair value at the conclusion of each interim and annual reporting period until the date of settlement, taking into consideration the probability that the performance conditions will be satisfied.

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

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

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

Net Income Per Unit.Computations of basic income per Common Unit are performed by dividing net income by the weighted average number of outstanding Common Units, and vested (and unissued) restricted units granted under the Partnership’s Restricted Unit Plans, as defined below, to retirement-eligible grantees. Computations of diluted income per Common Unit are performed by dividing net income by the weighted average number of outstanding Common Units and unissued restricted units granted under the Restricted Unit Plans. In computing diluted net income per Common Unit, weighted average units outstanding used to compute basic net income per Common Unit were increased by 222,419, 141,570 ~~198,298~~ and ~~238,589~~198,298 units for fiscal 2013, 2012 ~~2011~~ and ~~2010,~~2011, 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)~~comprehensive income. Other comprehensive income includes unrealized gains and losses on derivative instruments accounted for as cash flow hedges and reclassifications of realized losses on cash flow hedges into earnings, amortization of net actuarial losses and prior service credits into earnings and changes in the funded status of pension and other postretirement benefit plans.

In ~~June~~December 2011, the ~~FASB~~Financial Accounting Standards Board (“FASB”) issued an accounting standards update (“ASU”) regarding disclosures about offsetting assets and liabilities (“ASU 2011-11”). The new guidance requires an entity to ~~provide~~disclose information about offsetting and related arrangements to enable users of financial statements to understand the effect of those arrangements on its financial position. The guidance intends to enhance disclosures by requiring information about financial instruments and derivative instruments that are either offset in accordance with other US GAAP or subject to an enforceable master netting arrangement or similar agreement, irrespective of whether or not they are offset in the balance sheet. The new guidance is effective for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods, which will be the Partnership’s first quarter of its 2014 fiscal year. The Partnership is currently evaluating the impact of the new guidance on ~~increasing~~its future disclosures.

In February 2013, the ~~prominence of items reported in other comprehensive income. This update eliminates~~FASB issued an ASU to establish the ~~option~~effective date for the requirement to present components of reclassifications out of accumulated other comprehensive income ~~as part~~either parenthetically on the face of the ~~statement of partners’ capital and requires net income and the components of other comprehensive income be presented either in a single continuous statement of comprehensive income~~financial statements or in ~~two separate but consecutive statements. Early adoption of this updated~~the notes to the financial statements (“ASU 2013-02”). The guidance is ~~permitted, and it becomes~~ effective ~~retrospectively~~prospectively for ~~fiscal years~~annual periods beginning after December 15, ~~2011,~~2012, and interim periods within those annual periods, which will be the first quarter of the Partnership’s ~~2013~~2014 fiscal year. ~~This update does~~The adoption of ASU 2013-02 will not change the items that must be reported in other comprehensive ~~income, but will require the Partnership to change its historical practice of showing comprehensive income within the Statement of Partners�� Capital.~~income.

~~Subsequent Events.~~ The Partnership has evaluated all subsequent events that occurred after the balance sheet date through the date its financial statements were issued, and concluded there were no events or transactions occurring during this period that required recognition or disclosure in its financial statements, except for the following item from Note 8.

On November 13, 2012, the Partnership offered to exchange its existing unregistered 7.5% senior notes due 2018 and 7.375% senior notes due 2021 (the “Old Notes”) for an equal principal amount of 7.5% senior notes due 2018 and 7.375% senior notes due 2021 (the “Exchange Notes”), respectively, that have been registered under the Securities Act of 1933, as amended. The terms of the Exchange Notes are identical in all material respects (including principal amount, interest rate, maturity and redemption rights) to the Old Notes for which they may be exchanged, except that the Exchange Notes generally will not be subject to transfer restrictions. The exchange offer expires on December 13, 2012, unless extended.

As described in Note 1, the Partnership completed the acquisition of Inergy Propane on August 1, 2012. The acquisition of Inergy Propane (the “Inergy Propane Acquisition”) was consummated pursuant to a definitive agreement dated April 25, 2012 with Inergy, Inergy GP, LLC and Inergy Sales, as amended (the “Contribution Agreement”). Prior to the Acquisition Date, Inergy Propane transferred its interest in certain subsidiaries, as well as all of its rights and interests in the assets and properties of its wholesale propane supply, marketing and distribution business, and its rights and interest in the assets and properties of its West Coast natural gas liquids business, to Inergy. These assets were not included as part of the Inergy Propane business at the time of the transfer of the membership interests in Inergy Propane to the Partnership and were not part of the Inergy Propane Acquisition. The results of operations of Inergy Propane are included in the Partnership’s results of operations beginning on the Acquisition Date.

Pursuant to the Contribution Agreement, the Partnership agreed to issue $600,000 in new Common Units in the aggregate to Inergy and Inergy Sales (the “Equity Consideration”). In accordance with the Contribution Agreement, the number of Common Units issued to Inergy and Inergy Sales in the aggregate was determined by dividing $600,000 by the average of the high and low sales prices of the Partnership’s Common Units for the twenty consecutive trading days ending on the day prior to the execution of the Contribution Agreement, ~~(April 24, 2012),~~ which was determined to be $43.1885, resulting in 13,892,587 Common Units.

Also pursuant to the Contribution Agreement, the Partnership and its wholly-owned subsidiary Suburban Energy Finance Corp. commenced an offer to exchange (the “Exchange Offers”) any and all of the outstanding unsecured 7% senior notes due 2018 and 6⁷/₈%6.875% senior notes due 2021 issued by Inergy and Inergy Finance Corp., which had an aggregate principal amount outstanding of $1,200,000 (collectively, the “Inergy Notes”), for a combination of $1,000,000 in aggregate principal amount of new unsecured 7¹/₂%7.5% senior notes due 2018 and 7³/₈%7.375% senior notes due 2021 (collectively, the “SPH Notes”) issued by the Partnership and Suburban Energy Finance Corp. and up to $200,000 in cash to tendering noteholders (the “Exchange Offer Cash Consideration”). Pursuant to the Contribution Agreement, the Partnership was required to pay Inergy the difference, if any, between $200,000 and the actual Exchange Offer Cash Consideration paid in accordance with the terms of the Exchange Offers (such payment, the “Inergy Cash Consideration”). The Contribution Agreement provided that the Partnership would offer $65,000 in aggregate cash consent payments in connection with the Exchange Offers and that Inergy would pay $36,500 to the Partnership in cash on the Acquisition Date. The Exchange Offers expired and settled on August 1, 2012 (the “Settlement Date”). On the Settlement Date, the Partnership had received tenders and consents from holders representing approximately 98.09% of the total outstanding principal amount of the 2018 Inergy Notes, and tenders and consents from holders representing approximately 99.74% of the total outstanding principal amount of the 2021 Inergy Notes. Based on the results of the Exchange Offers, the Exchange Offer Cash Consideration due to tendering Inergy noteholders was $184,761. The Inergy Cash Consideration was satisfied by the issuance of 307,835 Common Units to Inergy and therefore, when combined with the Equity Consideration, the Partnership issued 14,200,422 Common Units in the aggregate to Inergy and Inergy Sales on August 1, 2012. Inergy distributed 14,058,418 of such Common Units to its unitholders on September 14, 2012.

On April 25, 2012, the Partnership received consents from the requisite lenders under the Amended Credit Agreement (as defined in Note 8) to enable it to incur additional indebtedness, make amendments to the Amended Credit Agreement to adjust certain covenants, and otherwise perform our obligations as contemplated by the Inergy Propane Acquisition. On August 1, 2012, the Operating Partnership executed an amendment to the Amended Credit Agreement to, among other things, provide for (i) a $250,000 senior secured 364-day incremental term loan facility (the “364-Day Facility”) and (ii) an increase in our revolving credit facility under the Amended Credit Agreement from $250,000 to $400,000. On the Acquisition Date, the Operating Partnership drew $225,000 on the 364-Day Facility, which, together with cash received from Inergy (pursuant to the Contribution Agreement) and cash on hand, was used to pay: (i) the consent fees and the Exchange Offer Cash Consideration, (ii) costs and fees related to the Exchange Offers, and (iii) costs and expenses related to the Inergy Propane Acquisition. On August 14, 2012 the Partnership repaid its borrowings of $225,000 under its 364-Day Facility with the proceeds from a public sale of 6,300,000 Common Units that closed on that date.

The fair value of the purchase price for Inergy Propane as determined on the Acquisition Date was $1,890,915, consisting of: (i) $1,075,043 of newly issued senior notes (with an aggregate par value of $1,000,000) and $184,761 in cash to tendering Inergy noteholders pursuant to the Exchange Offers; (ii) $65,000 in cash paid to the Inergy noteholders for the consent payments pursuant to the consent solicitations; (iii) $590,027 of new Suburban Common Units (consisting of 14,200,422 Common Units), which were ~~distributed~~issued to Inergy and Inergy Sales, all but $5,942 (consisting of 142,004 Common Units) of which were subsequently distributed by Inergy to its unitholders; reduced by (iv) $23,916 of cash received from Inergy pursuant to the Contribution Agreement (the cash consideration from Inergy includes the $36,500 discussed above and is net of amounts owed to Inergy by the Partnership at the Acquisition Date). The fair value of the newly issued senior notes was determined using Level 2 inputs and the fair value of the equity issued to Inergy and Inergy Sales was determined using Level 1 inputs.

During the third quarter of fiscal 2013, the Partnership finalized the third party valuations of the Acquisition Date fair value of certain assets acquired in the Inergy Propane Acquisition, principally property, plant and equipment, and intangible assets. The consolidated balance ~~sheet at~~sheets as of September 28, 2013 and September 29, 2012 ~~reflects a preliminary~~reflect the final allocation of the purchase price to the assets acquired and liabilities ~~assumed.~~ assumed in this business combination.

The final purchase price allocation resulted in the ~~process~~following adjustments to the provisional fair value estimates: property, plant and equipment decreased $33,302, intangible assets (principally customer relationships) increased $39,583, other current assets decreased $765 and other noncurrent liabilities increased $646. The net effect of ~~obtaining information required~~these adjustments resulted in a $4,870 decrease to ~~determine the fair values of certain assets and liabilities acquired, principally non-current tangible and intangible assets. The Partnership expects to finalize the determination~~goodwill as of the Acquisition ~~Date fair value amounts by July 31, 2013. The preliminary purchase price allocation as of August 1, 2012 is as follows:~~

~~Goodwill associated with the Inergy Propane Acquisition principally results from synergies expected from combining the operations and from assembled workforce.~~

~~Acquisition-related expenses associated with the Inergy Propane Acquisition, as shown in the Consolidated Statements of Operations, totaled $17,916 for the year ended September 29, 2012.~~

The Inergy Propane Acquisition is consistent with key elements of the Partnership’s strategy for operational growth, which is to focus on businesses with a relatively steady cash flow that will extend the Partnership’s presence in strategically attractive markets and complement its existing business segments. For the year ended September 30, 2011, Inergy Propane sold approximately 325,600 gallons of propane and 39,000 gallons of fuel oil and refined fuels to its retail customers in 33 states.Date. As a result, results of ~~achieving planned strategic integration milestones, it is impracticable~~operations for fiscal 2012 have been revised for a $205 decrease to ~~determine the impact of the Inergy Propane Acquisition operations on the revenues~~depreciation expense and ~~earnings of the Partnership.~~a $1,449 increase to amortization expense.

The following presents unaudited pro forma combined financial information as if the Inergy Propane Acquisition had occurred on September 26, 2010, the first day of the Partnership’s 2011 fiscal ~~year.~~year, as adjusted for the final purchase price allocation. The unaudited pro forma combined financial information was prepared under the assumption that the net proceeds from the issuance of the 6,300,000 Common Units on August 14, 2012 ~~(described in Note. 14)~~ were used to fund the portion of the Inergy Propane Acquisition that was originally financed through the 364-Day Facility (which ~~as described above,~~ was repaid two weeks after the ~~acquisition date)~~Acquisition Date). As a result, the ~~common units~~Common Units were assumed to have been issued on September 26, 2010, and, in turn, the pro forma results for the fiscal year ended September 29, 2012 do not include any interest costs associated with the 364-Day Facility.

   Year Ended
   September 29,
2012    September 24,
2011
Revenues
   $ 1,842,698       $ 2,242,876
Net income
   $ 20,288       $ 123,751
Income per common unit

Basic
   $ 0.36       $ 2.21
Diluted
   $ 0.36       $ 2.20

The unaudited pro forma combined financial information is not necessarily indicative of the results that would have occurred had the Inergy Propane Acquisition occurred on the date indicated nor is it necessarily indicative of future operating results.

If the fair values of the tangible and intangible assets acquired increased by 10% from the provisional fair values as of August 1, 2012, goodwill would decrease by 10%, annual depreciation expense would increase by $4,359 and amortization expense would increase by $4,791. If the fair values of the tangible and intangible assets acquired decreased by 10% from the provisional fair values as of August 1, 2012, goodwill would increase by 10%, annual depreciation expense would decrease by $3,293 and amortization expense would decrease by $4,279, respectively.

In accordance with the Contribution Agreement, the Partnership and Inergy entered into a transition services agreement (the “TSA”) whereby Inergy will provide certain services to the Partnership. The principal services include general business continuity, information technology, accounting, tax and administrative services. Services under the TSA will be provided through the expiration of the term relating to each service or until such time as mutually agreed by the parties. Amounts associated with the services were not material.

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

The following summarizes the quarterly distributions per Common Unit declared and paid in respect of each of the quarters in the three fiscal years in the period ended September ~~29, 2012:~~28, 2013:


	As of				As of
	September 29,		September 24,		September 28,		September 29,
	2012		2011		2013		2012
Propane, fuel oil and refined fuels and natural gas	$	83,543	$	64,601	$	75,885	$	83,543
Appliances		4,633		1,306		1,738		4,633

	$	88,176	$	65,907	$	77,623	$	88,176

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


	As of						As of
	September 29,			September 24,			September 28,			September 29,
	2012			2011			2013			2012
Land and improvements	$	206,130		$	27,904		$	207,516		$	195,803
Buildings and improvements		112,610			82,639			104,137			114,960
Transportation equipment		73,428			19,067			71,815			70,058
Storage facilities		115,445			79,525			113,571			115,905
Equipment, primarily tanks and cylinders		836,757			485,859			830,282			814,342
Computer systems		48,320			47,718			49,049			48,320
Construction in progress		4,043			2,704			4,472			4,043

		1,396,733			745,416			1,380,842			1,363,431
Less: accumulated depreciation		(427,408	)		(407,291	)		(492,610	)		(427,203	)

	$	969,325		$	338,125		$	888,232		$	936,228

Depreciation expense for fiscal 2013, 2012 ~~2011~~ and ~~2010~~2011 amounted to ~~$35,237,~~$72,353, $35,032 and $32,368, ~~and $28,411,~~ respectively.

The Partnership’s fiscal ~~2012~~2013 and fiscal ~~2011~~2012 annual goodwill impairment review resulted in no adjustments to the carrying amount of goodwill.

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


	Propane		Fuel oil and refined fuels			Natural gas and electricity		Total
Balance as of September 24, 2011
Goodwill	$	265,313	$	10,900		$	7,900	$	284,113
Accumulated adjustments		—		(6,462	)		—		(6,462	)

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

Goodwill acquired during fiscal 2012	$	803,958	$	10,690		$	—	$	814,648
											Propane		Fuel oil and refined fuels			Natural gas and electricity		Total
Balance as of September 29, 2012
Goodwill	$	1,069,271	$	21,590		$	7,900	$	1,098,761		$	1,075,091	$	10,900		$	7,900	$	1,093,891
Accumulated adjustments		—		(6,462	)		—		(6,462	)		—		(6,462	)		—		(6,462	)

	$	1,069,271	$	15,128		$	7,900	$	1,092,299		$	1,075,091	$	4,438		$	7,900	$	1,087,429

Balance as of September 28, 2013
Goodwill											$	1,075,091	$	10,900		$	7,900	$	1,093,891
Accumulated adjustments												—		(6,462	)		—		(6,462	)

											$	1,075,091	$	4,438		$	7,900	$	1,087,429


	As of						As of
	September 29,			September 24,			September 28,			September 29,
	2012			2011			2013			2012
Customer relationships	$	424,409		$	26,523		$	466,959		$	466,959
Non-compete agreements		28,665			3,756			26,815			26,815
Tradenames		4,599			1,499			3,482			3,482
Other		1,967			1,967			1,967			1,967

		459,640			33,745			499,223			499,223

Less: accumulated amortization
Customer relationships		(18,576	)		(15,036	)		(71,382	)		(20,105	)
Non-compete agreements		(2,338	)		(760	)		(8,138	)		(2,305	)
Tradenames		(1,441	)		(1,162	)		(2,040	)		(1,394	)
Other		(801	)		(709	)		(892	)		(801	)

		(23,156	)		(17,667	)		(82,452	)		(24,605	)

	$	436,484		$	16,078		$	416,771		$	474,618

Aggregate amortization expense related to other intangible assets for fiscal 2013, 2012 and 2011 was $58,031, $12,002 and ~~2010 was $10,553,~~ $3,260, ~~and $2,423,~~ respectively. Aggregate amortization expense for each of the five succeeding fiscal years related to other intangible assets held as of September ~~29, 2012~~28, 2013 is as follows: ~~2013—$47,570;~~ 2014—$~~47,439;~~57,480; 2015—$~~47,277;~~56,767; 2016—$~~46,658~~53,971; 2017—$52,686 and ~~2017—~~2018—$~~45,758.~~52,236.

For federal income tax purposes, as well as for state income tax purposes in the majority of the states in which the Partnership operates, the earnings attributable to the Partnership ~~as a separate legal entity,~~ and the Operating Partnership are not subject to income tax at the partnership level. With the exception of those states that impose an entity-level income tax on partnerships, the taxable income or loss attributable to the Partnership ~~as a separate legal entity,~~ and to the Operating Partnership, which may vary substantially from the income (loss) before income taxes reported by the Partnership in the consolidated statement of operations, are includable in the federal and state income tax returns of the ~~individual partners.~~Common Unitholders. The aggregate difference in the basis of the Partnership’s net assets for financial and tax reporting purposes cannot be readily determined as the Partnership does not have access to each ~~partner’s~~Common Unitholder’s basis in the Partnership.

As described in Note 1 and Note 2, the earnings of the Corporate Entities are subject to corporate level federal and state income tax. However, based upon past performance, the Corporate Entities are currently reporting an income tax provision composed primarily of minimum state income taxes. A full valuation allowance has been provided against the deferred tax assets based upon an analysis of all available evidence, both negative and positive at the balance sheet date, which, taken as a whole, indicates that it is more likely than not that sufficient future taxable income will not be available to utilize the assets. Management’s periodic reviews include, among other things, the nature and amount of the taxable income and expense items, the expected timing when assets will be used or liabilities will be required to be reported and the reliability of historical profitability of businesses expected to provide future earnings. Furthermore, management considered tax-planning strategies it could use to increase the likelihood that the deferred tax assets will be realized.

The income tax provision of all the legal entities included in the Partnership’s consolidated statement of operations, which is composed primarily of state income taxes in the few states that impose taxes on partnerships and minimum state income taxes on the Corporate Entities, consists of the following:


	Year Ended						Year Ended
	September 29,		September 24,		September 25,		September 28,		September 29,		September 24,
	2012		2011		2010		2013		2012		2011
Current
Federal	$	18	$	135	$	177	$	26	$	18	$	135
State and local		119		749		1,005		581		119		749

		137		884		1,182		607		137		884
Deferred		—		—		—		—		—		—

	$	137	$	884	$	1,182	$	607	$	137	$	884

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


	Year Ended									Year Ended
	September 29,			September 24,			September 25,			September 28,			September 29,			September 24,
	2012			2011			2010			2013			2012			2011
Income tax provision at federal statutory tax rate	$	706		$	40,548		$	40,361		$	27,792		$	271		$	40,548
Impact of Partnership income not subject to federal income taxes		(5,000	)		(39,952	)		(38,808	)		(35,187	)		(4,564	)		(39,952	)
Permanent differences		244			239			2,051			71			244			239
Transfer of assets to Corporate Entities		13,420			—			—			—			8,181			—
Change in valuation allowance		(8,990	)		(454	)		(4,806	)		9,771			(3,567	)		(454	)
State income taxes		(659	)		492			2,247			(1,135	)		339			492
Other		416			11			137			(705	)		(767	)		11

Provision for income taxes—current and deferred	$	137		$	884		$	1,182		$	607		$	137		$	884

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


	As of						As of
	September 29,			September 24,			September 28,			September 29,
	2012			2011			2013			2012
Deferred tax assets:
Net operating loss carryforwards	$	37,256		$	32,938		$	46,356		$	37,255
Allowance for doubtful accounts		652			1,323			878			652
Inventory		563			658			525			563
Intangible assets		—			1,201			577			927
Deferred revenue		2,631			1,303			2,188			2,631
Derivative instruments		71			71			109			71
AMT credit carryforward		1,086			1,086			1,086			1,086
Other accruals		1,926			1,936			2,062			1,926

Total deferred tax assets		44,185			40,516			53,781			45,111

Deferred tax liabilities:
Property, plant and equipment		10,462			314			7,375			8,476
Intangible assets		2,511			—

Total deferred tax liabilities		12,973			314			7,375			8,476

Net deferred tax assets		31,212			40,202			46,406			36,635
Valuation allowance		(31,212	)		(40,202	)		(46,406	)		(36,635	)

Net deferred tax assets	$	—		$	—		$	—		$	—

After the Inergy Propane Acquisition, the Partnership contributed all of the Inergy Propane assets and liabilities to the Operating Partnership which, in turn, contributed the fuel oil and refined fuels and service assets and liabilities to the Corporate Entities. At the time of the transfer, the Corporate Entities recognized a deferred tax liability for the difference between the book basis of the assets received and their tax basis. The recognition of that deferred tax liability was offset by the release of a portion of the valuation allowance that previously existed on the net deferred tax assets. Thus, the transfer of these assets had no impact on net income for fiscal 2012.

On August 1, 2012, the Partnership and its 100%-owned subsidiary, Suburban Energy Finance Corp., issued $496,557 in aggregate principal amount of unregistered 7.5% senior notes due October 1, 2018 (the “2018 Senior Notes”) and $503,443 in aggregate principal amount of unregistered 7.375% senior notes due August 1, 2021 (the “2021 Senior Notes”) in a private placement in connection with the Inergy Propane Acquisition described in Note 3. Based on market rates for similar issues, the 2018 Senior Notes and 2021 Senior Notes were valued at 106.875% and 108.125%, respectively, of the principal amount, on the ~~date of acquisition~~Acquisition Date as they were issued in exchange for Inergy’s outstanding notes, not for cash. ~~The 2018 Senior Notes and 2021 Senior Notes were issued at 106.875% and 108.125%, respectively, of the principal amount.~~ The 2018 Senior Notes require semi-annual interest payments in April and October, and the 2021 Senior Notes require semi-annual interest payments in February and August.

The 2018 Senior Notes are redeemable, at the Partnership’s option, in whole or in part, at any time after October 1, 2014, in each case at the redemption prices described in the table below, together with any accrued and unpaid interest to the date of the redemption.

The 2021 Senior Notes are redeemable, at the Partnership’s option, in whole or in part, at any time after August 1, 2016, in each case at the redemption prices described in the table below, together with any accrued and unpaid interest to date of the redemption.

On ~~November 13,~~December 19, 2012, the Partnership ~~offered~~completed an offer to exchange its existing unregistered 7.5% senior notes due 2018 and 7.375% senior notes due 2021 (the “Old Notes”) for an equal principal amount of 7.5% senior notes due 2018 and 7.375% senior notes due 2021 (the “Exchange Notes”), respectively, that have been registered under the Securities Act of 1933, as amended. The terms of the Exchange Notes are identical in all material respects (including principal, ~~amount,~~ interest rate, maturity and redemption rights) to the Old Notes for which they ~~may be~~were exchanged, except that the Exchange Notes generally will not be subject to transfer restrictions. ~~The exchange offer expires~~

On August 2, 2013, the Partnership repurchased, pursuant to an optional redemption, $133,400 of its 2021 Senior Notes using net proceeds from the May 2013 public offering and net proceeds from the underwriters’ exercise of their over-allotment option to purchase additional Common Units. In addition, on ~~December 13, 2012, unless otherwise extended.~~August 6, 2013, the Partnership repurchased $23,863 of 2021 Senior Notes in a private transaction using cash on hand. In connection with these repurchases, which totaled $157,263 in aggregate principal amount, the Partnership recognized a loss on the extinguishment of debt of $2,144 consisting of $11,759 for the repurchase premium and related fees, as well as the write-off of $2,064 and ($11,678) in unamortized debt origination costs and unamortized premium, respectively.

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

The 2020 Senior Notes are redeemable, at the Partnership’s option, in whole or in part, at any time after March 15, 2015, in each case at the redemption prices described in the table below, together with any accrued and unpaid interest to the date of the redemption.

The Partnership’s obligations under the 2018 Senior Notes, 2020 Senior Notes and 2021 Senior Notes (collectively, the “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 Senior Notes are structurally subordinated to, which means they rank effectively behind, any debt and other liabilities of the Operating Partnership. The Senior Notes have a change of control provision that would require the Partnership to offer to repurchase the notes at 101% of the principal amount repurchased, if a change of control, as defined in the indenture, occurs and is followed by a rating decline (a decrease in the rating of the notes by either Moody’s Investors Service or Standard and Poor’s Rating Group by one ofor more gradations) within 90 days of the consummation of the change of control.

The Operating Partnership has a credit agreement, as amended on January 5, 2012 and August 1, 2012 (the “Amended Credit Agreement”) that provides for a five-year $400,000 revolving credit facility (the “Revolving Credit Facility”), of which $100,000 was outstanding as of September ~~29, 2012~~28, 2013 and September ~~24, 2011.~~29, 2012. Borrowings under the Revolving Credit Facility may be used for general corporate purposes, including working capital, capital expenditures and acquisitions. 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.

The amendment to the credit agreement on January 5, 2012 amended the previous credit agreement to, among other things, extend the maturity date from June 25, 2013 to January 5, 2017, reduce the borrowing rate and commitment fees, and amend certain affirmative and negative covenants. ~~On the date~~As of ~~the~~ January 5, 2012, ~~amendment,~~ the Operating Partnership had borrowings of $100,000 outstanding under the revolving credit facility of the previous credit agreement, and rolled those borrowings into the Revolving Credit Facility of the Amended Credit Agreement. ~~In addition,~~Also, at ~~the~~such time, ~~the January 5, 2012 amendment was entered into,~~ the Operating Partnership had letters of credit issued under the revolving credit facility of the previous credit agreement primarily in support of retention levels under its self-insurance programs, all of which have been rolled into the Revolving Credit Facility of the Amended Credit Agreement.

On April 25, 2012, the Partnership received consents from the requisite lenders under the Amended Credit Agreement to enable it to incur additional indebtedness, make amendments to the Amended Credit Agreement to adjust certain covenants, and otherwise perform our obligations as contemplated by the Inergy Propane Acquisition. On August 1, 2012, the Operating Partnership executed an amendment to the Amended Credit Agreement to, among other things, provide for (i) a $250,000 senior secured 364-Day Facility and (ii) an increase in our revolving credit facility under the Amended Credit Agreement from $250,000 to $400,000. On the Acquisition Date, the Operating Partnership drew $225,000 on the 364-Day Facility, which was used to fund a portion of the Inergy Propane Acquisition, including costs and expenses related to the acquisition. The Partnership repaid the $225,000 of borrowings under the 364-Day Facility on August 14, 2012 with the net proceeds from the public issuance of Common Units on August 14, 2012.

The amendment to the Amended Credit Agreement on August 1, 2012 also amended certain restrictive and affirmative covenants applicable to the Operating Partnership and the Partnership, as well as certain financial covenants, including (a) requiring the Partnership’s consolidated interest coverage ratio, as defined in the amendment, to be not less than 2.0 to 1.0 as of the end of any fiscal quarter; (b) prohibiting the total consolidated leverage ratio, as defined in the amendment, of the Partnership from being greater than 7.0 to 1.0 as of the end of any fiscal quarter. The minimum consolidated interest coverage ratio increases over time, and commencing with the ~~second~~third quarter of fiscal ~~2015,~~2014, such minimum ratio will be 2.5 to 1.0. The maximum consolidated leverage ratio decreases over time, ~~and commencing~~as well as upon the occurrence of certain events (such as the issuance of Common Units where the net proceeds from the issuance exceed certain thresholds). Commencing with the ~~first~~second quarter of fiscal ~~2015,~~2013, such maximum ratio will be 4.75 to ~~1.0.~~1.0 (or 5.0 to 1.0 during an acquisition period as defined in the amendment) as a result of the issuance of Common Units in August 2012. As of September ~~29, 2012~~28, 2013 the minimum consolidated interest coverage ratio and maximum consolidated leverage ratio was ~~2.0~~2.25 to 1.0 and ~~5.75~~4.75 to 1.0, respectively.

The Partnership acts as a guarantor with respect to the obligations of the Operating Partnership under the Amended Credit Agreement pursuant to the terms and conditions set forth therein. The obligations under the Amended 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.

Borrowings under the Revolving Credit Facility of the Amended Credit Agreement 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 plus¹⁄₂ of 1%, the agent bank’s prime rate, or LIBOR plus 1%, plus in each case the applicable margin. The applicable margin is dependent upon the Partnership’s ratio of total debt to EBITDA on a consolidated basis, as defined in the Revolving Credit Facility. As of September 28, 2013, the interest rate for the Revolving Credit Facility was approximately 2.8%. The interest rate and the applicable margin will be reset at the end of each calendar quarter.

In connection with the previous revolving credit facility, the Operating Partnership entered into an interest rate swap agreement with a notional amount of $100,000, ~~and~~ an effective date of March 31, 2010 and termination date of June 25, 2013. Under the interest rate swap agreement, the Operating Partnership ~~will pay~~paid 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~~paid to the Operating Partnership a floating rate, namely LIBOR, on the same notional principal amount. The interest rate swap ~~has been~~was designated as a cash flow hedge. In connection with the Amended Credit Agreement, the Operating Partnership entered into a forward starting interest rate swap agreement with a notional amount of $100,000, an effective date of June 25, 2013 ~~effective date, which coincides with the maturity of the existing interest rate swap agreement,~~ and a ~~maturity~~termination date of January 5, 2017. Under this forward starting interest rate swap agreement, the Operating Partnership will pay a fixed interest rate of 1.63% to the issuing lender on the notional principal amount outstanding, and the issuing lender will pay to the Operating Partnership a floating rate, namely LIBOR, on the same notional principal amount. The forward starting interest rate swap has been designated as a cash flow hedge.

As of September ~~29, 2012,~~28, 2013, the Partnership had standby letters of credit issued under the Revolving Credit Facility in the aggregate amount of ~~$46,842~~$46,742 which expire periodically through ~~September 1, 2013.~~April 3, 2014. Therefore, as of September ~~29, 2012~~28, 2013 the Partnership had available borrowing capacity of ~~$253,158~~$253,258 under the Revolving Credit Facility.

The Amended Credit Agreement and the Senior Notes both contain various restrictive and affirmative covenants applicable to the Operating Partnership and the Partnership, respectively, including (i) restrictions on the incurrence of additional indebtedness, and (ii) restrictions on certain liens, investments, guarantees, loans, advances, payments, mergers, consolidations, distributions, sales of assets and other transactions. Under the Amended Credit Agreement and the indentures governing the Senior Notes, the Operating Partnership isand the Partnership 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 with respect to the indentures governing the Senior Notes, 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 Senior Notes and the Amended Credit Agreement as of September ~~29, 2012.~~28, 2013.

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. During fiscal 2013, the Partnership recognized charges of $2,064 to write-off unamortized debt origination costs associated with the repurchase of its 2021 Senior Notes. During fiscal 2012, the Partnership capitalized $14,885 and $10,314 for costs incurred in connection with issuance of new senior notes and the amendments to the Amended Credit Agreement, respectively. The Partnership recognized charges of $2,249 to write-off unamortized debt origination costs associated with the amendments to the Amended Credit Agreement on January 5, 2012 and the repayment of borrowings under the 364-Day Facility. Other assets at September ~~29, 2012~~28, 2013 and September ~~24, 2011~~29, 2012 include debt origination costs with a net carrying amount of ~~$28,076~~$21,254 and ~~$7,207,~~$28,076, respectively.

The aggregate amounts of long-term debt maturities subsequent to September ~~29, 2012~~28, 2013 are as follows: fiscal ~~2013~~2014 through fiscal 2016: $-0-; fiscal 2017: $100,000; fiscal 2018: $496,557; and thereafter: ~~$1,250,000.~~$596,180.

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~~re-measurement of the award’s fair value at the conclusion of each interim and annual reporting period until the date of settlement, taking into consideration the probability that the performance conditions will be satisfied.

Restricted Unit Plans. In fiscal 2000 and fiscal 2009, the Partnership adopted the Suburban Propane Partners, L.P. 2000 Restricted Unit Plan and 2009 Restricted Unit Plan (collectively, the “Restricted Unit Plans”), respectively, which authorizes the issuance of Common Units to executives, managers and other employees and members of the Board of Supervisors of the Partnership. The total number of Common Units authorized for issuance under the Restricted Unit Plans was 1,902,122 as of September ~~29, 2012.~~28, 2013. Unless otherwise stipulated by the Compensation Committee of the Partnership’s Board of Supervisors on or before the grant date, restricted units issued under the Restricted Unit Plans vest over time with 25% of the Common Units vesting at the end of each of the third and fourth anniversaries of the grant date and the remaining 50% of the Common Units vesting at the end of the fifth anniversary of the grant date. In accordance with an August 6, 2013 amendment to the Restricted Unit Plans, unless otherwise stipulated by the Compensation Committee of the Partnership’s Board of Supervisors on or before the grant date, all restricted unit awards granted after the date of the amendment will vest 33.33% on each of the first three anniversaries of the award grant date. The Restricted Unit Plans participants are not eligible to receive quarterly distributions on, or vote, their respective restricted units until vested. Restricted units cannot be sold or transferred prior to vesting. The value of the restricted unit is established by the market price of the Common Unit on the date of grant, net of estimated future distributions during the vesting period. Restricted units are subject to forfeiture in certain circumstances as defined in the Restricted Unit Plans. Compensation expense for the unvested awards is recognized ratably over the vesting periods and is net of estimated forfeitures.


				Weighted Average						Weighted Average
				Grant Date Fair						Grant Date Fair
	Units			Value Per Unit
Outstanding September 26, 2009		415,295		$	28.89
Granted		160,771			32.11
Forfeited		(4,693	)		(30.31	)
Issued		(90,106	)		(30.37	)
							Units			Value Per Unit
Outstanding September 25, 2010		481,267			29.67			481,267		$	29.67
Granted		136,241			39.54			136,241			39.54
Forfeited		(21,290	)		(33.05	)		(21,290	)		(33.05	)
Issued		(110,795	)		(27.82	)		(110,795	)		(27.82	)

Outstanding September 24, 2011		485,423			32.71			485,423			32.71
Granted		108,674			32.60			108,674			32.60
Forfeited		(12,225	)		(30.78	)		(12,225	)		(30.78	)
Issued		(139,021	)		(33.14	)		(139,021	)		(33.14	)

Outstanding September 29, 2012		442,851		$	32.68			442,851			32.68
Granted								200,933			23.42
Forfeited								(3,497	)		(32.15	)
Issued								(112,660	)		(32.01	)

Outstanding September 28, 2013								527,627		$	29.30

As of September ~~29, 2012,~~28, 2013, unrecognized compensation cost related to unvested restricted units awarded under the Restricted Unit Plans amounted to ~~$5,430.~~$6,141. Compensation cost associated with the unvested awards is expected to be recognized over a weighted-average period of ~~1.9~~1.8 years. Compensation expense for the Restricted Unit Plans for fiscal 2013, 2012 and 2011 was $3,888, $4,059 and ~~2010 was $4,059,~~ $3,922, ~~and $4,005,~~ respectively.

Long-Term Incentive ~~Plan.~~Plans. The Partnership has a non-qualified, unfunded long-term incentive plan for officers and key employees (the “LTIP”) which provides for payment, in the form of cash, for an award of equity-based compensation at the end of a three-year performance period. The level of compensation earned under the LTIP in effect on September 28, 2013 (“Existing LTIP”) is based on the market performance of the Partnership’s Common Units on the basis of total return to Unitholders (“TRU”) compared to the TRU of a predetermined peer group comprised of other publicly traded partnerships (master limited partnerships), as approved by the Compensation Committee of the Partnership’s Board of Supervisors, over the same three-year performance period. Compensation expense, which includes adjustments to previously recognized compensation expense for current period changes in the fair value of unvested awards, for fiscal 2013, 2012 and 2011 was $1,439, ($340) and ~~2010 was ($340),~~ $1,504, ~~and $3,058,~~ respectively. The cash payouts in fiscal 2013, 2012 ~~2011~~ and ~~2010,~~2011, which related to the fiscal 2010, 2009 ~~2008~~ and ~~2007~~2008 awards, were $-0-, $3,336 and $2,697, respectively.

On August 6, 2013, the Compensation Committee of the Partnership’s Board of Supervisors adopted the 2014 Long-Term Incentive Plan of the Partnership (“2014 LTIP”) as a replacement for Existing LTIP. The 2014 LTIP became effective October 1, 2013. The major difference between the 2014 LTIP and ~~$2,741, respectively.~~

Defined Contribution Plan.The Partnership has an employee Retirement Savings and Investment Plan (the “401(k) Plan”) covering most employees. Employer matching contributions relating to the 401(k) Plan are a percentage of the participating employees’ elective contributions. The percentage of the Partnership’s contributions are based on a sliding scale depending on the Partnership’s achievement of annual performance targets. These contributions totaled $1,915, $1,359 ~~$1,201~~ and ~~$2,504~~$1,201 for fiscal 2013, 2012 and 2011, ~~and 2010,~~ respectively.

Pension Benefits.The Partnership has a noncontributory defined benefit pension plan which was originally designed to cover all eligible employees of the Partnership who met certain requirements as to age and length of service. Effective January 1, 1998, the Partnership amended its defined benefit pension plan to provide benefits under a cash balance formula as compared to a final average pay formula which was in effect prior to January 1, 1998. Effective January 1, 2000, participation in the defined benefit pension plan was limited to eligible existing participants on that date with no new participants eligible to participate in the plan. On September 20, 2002, the Board of Supervisors approved an amendment to the defined benefit pension plan whereby, effective January 1, 2003, future service credits ceased and eligible employees receive interest credits only toward their ultimate retirement benefit.

Contributions, as needed, are made to a trust maintained by the Partnership. Contributions to the defined benefit pension plan are made by the Partnership in accordance with the Employee Retirement Income Security Act of 1974 minimum funding standards plus additional amounts made at the discretion of the Partnership, which may be determined from time to time. There were no minimum funding requirements for the defined benefit pension plan for fiscal 2013, 2012 ~~2011~~ or ~~2010.~~2011. During the last decade, cash balance plans came under increased scrutiny which resulted in litigation pertaining to the cash balance feature and the Internal Revenue Service (“IRS”) issued additional regulations governing these types of plans. In fiscal 2010, the IRS completed its review of the Partnership’s defined benefit pension plan and issued a favorable determination letter pertaining to the cash balance formula. However, there can be no assurances that future legislative developments will not have an adverse effect on the Partnership’s results of operations or cash flows.

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

The Partnership recognizes the funded status of pension and other postretirement benefit plans as an asset or liability on the balance sheet and recognizes changes in the funded status in other 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.

Projected Benefit Obligation, Fair Value of Plan Assets and Funded Status. The following tables provide a reconciliation of the changes in the benefit obligations and the fair value of the plan assets for fiscal ~~2012~~2013 and ~~2011~~2012 and a statement of the funded status for both years. Under the Partnership’s cash balance defined benefit pension plan, the accumulated benefit obligation and the projected benefit obligation are the same.


																			Retiree Health and Life Benefits
	Pension Benefits						Retiree Health and Life Benefits						Pension Benefits						Retiree Health and Life Benefits
	2012			2011			2012			2011			2013			2012			2013			2012
Reconciliation of benefit obligations:
Benefit obligation at beginning of year	$	159,119		$	157,626		$	20,895		$	20,932		$	165,906		$	159,119		$	20,232		$	20,895
Service cost		—			—			7			7			—			—			8			7
Interest cost		6,311			6,822			802			855			5,229			6,311			586			802
Actuarial loss (gain)		14,089			9,165			(74	)		631
Actuarial (gain) loss														(11,446	)		14,089			(1,784	)		(74	)
Lump sum benefits paid		(5,498	)		(6,365	)		—			—			(3,155	)		(5,498	)		—			—
Ordinary benefits paid		(8,115	)		(8,129	)		(1,398	)		(1,530	)		(7,903	)		(8,115	)		(1,288	)		(1,398	)

Benefit obligation at end of year	$	165,906		$	159,119		$	20,232		$	20,895		$	148,631		$	165,906		$	17,754		$	20,232

Reconciliation of fair value of plan assets:
Fair value of plan assets at beginning of year	$	132,898		$	139,889		$	—		$	—		$	133,873		$	132,898		$	—		$	—
Actual return on plan assets		14,588			7,503			—			—			(2,039	)		14,588			—			—
Employer contributions		—			—			1,398			1,530			—			—			1,288			1,398
Lump sum benefits paid		(5,498	)		(6,365	)		—			—			(3,155	)		(5,498	)		—			—
Ordinary benefits paid		(8,115	)		(8,129	)		(1,398	)		(1,530	)		(7,903	)		(8,115	)		(1,288	)		(1,398	)

Fair value of plan assets at end of year	$	133,873		$	132,898		$	—		$	—		$	120,776		$	133,873		$	—		$	—

Funded status:
Funded status at end of year	$	(32,033	)	$	(26,221	)	$	(20,232	)	$	(20,895	)	$	(27,855	)	$	(32,033	)	$	(17,754	)	$	(20,232	)

Amounts recognized in consolidated balance sheets consist of:
Net amount recognized at end of year	$	(32,033	)	$	(26,221	)	$	(20,232	)	$	(20,895	)	$	(27,855	)	$	(32,033	)	$	(17,754	)	$	(20,232	)
Less: Current portion		—			—			1,427			1,669			—			—			1,427			1,427

Non-current benefit liability	$	(32,033	)	$	(26,221	)	$	(18,805	)	$	(19,226	)	$	(27,855	)	$	(32,033	)	$	(16,327	)	$	(18,805	)

Amounts not yet recognized in net periodic benefit cost and included in accumulated other comprehensive income (loss):
Actuarial net (loss) gain	$	(59,397	)	$	(59,502	)	$	1,899		$	1,825		$	(49,986	)	$	(59,397	)	$	3,683		$	1,899
Prior service credits		—			—			1,869			2,358			—			—			1,379			1,869

Net amount recognized in accumulated other comprehensive (loss) income	$	(59,397	)	$	(59,502	)	$	3,768		$	4,183		$	(49,986	)	$	(59,397	)	$	5,062		$	3,768

Amounts recognized in other comprehensive income included net actuarial ~~losses arising during the period of $5,166 and $7,957 for pension benefits for fiscal 2012 and 2011, respectively, and net actuarial~~ (gains) losses arising during the period of ($~~74)~~4,126) and ~~$631~~$5,166 for pension benefits for fiscal 2013 and 2012, respectively, and net actuarial (gains) arising during the period of ($1,784) and ($74) for other postretirement benefits for fiscal ~~2012~~2013 and ~~2011,~~2012, respectively. The amounts in accumulated other comprehensive loss as of September ~~29, 2012~~28, 2013 that are expected to be recognized as components of net periodic benefit costs during fiscal ~~2013~~2014 are expenses of ~~$5,285~~$4,492 and credits of ~~$(478)~~$(671) for pension and other postretirement benefits, respectively.

Plan Assets. The Partnership’s investment policies and strategies, as set forth in the Investment Management Policy and Guidelines, are monitored by a Benefits Committee comprised of five members of management. The Partnership employs a liability driven investment strategy, which seeks to increase the correlation of the plan’s assets and liabilities to reduce the volatility of the plan’s funded status. This strategy has resulted in an asset allocation that is largely comprised of investments in funds of fixed income securities. The target asset mix is as follows: (i) fixed income securities portion of the portfolio should range between ~~75%~~80% and ~~95%~~90%; and (ii) equity securities portion of the portfolio should range between 5%10% and ~~25%~~20%.

The following table presents the actual allocation of assets held in trust as of:


	September			September			September			September
	29, 2012			24, 2011			28, 2013			29, 2012
Fixed income securities		85	%		88	%		85	%		85	%
Equity securities		15	%		12	%		15	%		15	%

		100	%		100	%		100	%		100	%

In accordance with current accounting guidance, the Partnership’s valuations include the use of the funds’ reported net asset values for commingled fund investments and private investment funds. Commingled funds are valued at the net asset value for their underlying securities. The Partnership further corroborates the above valuations with observable market data using level ~~1 and~~ 2 inputs within the fair value framework. The assets of the defined benefit pension plan have no significant concentration of risk and there are no restrictions on these investments.

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


					September 28,		September 29,
	September 29, 2012		September 24, 2011		2013		2012
Short term investments (1)	$	1,309	$	1,439	$	1,516	$	1,309

Equity securities: (1) (2)
Domestic		13,651		10,823		11,780		13,187
International		6,263		5,342		5,959		6,727
Fixed income securities (1) (3)		112,650		115,294		101,521		112,650

	$	133,873	$	132,898	$	120,776	$	133,873

Projected Contributions and Benefit Payments. There are no projected minimum funding requirements under the Partnership’s defined benefit pension plan for fiscal ~~2013.~~2014. Estimated future benefit payments for both pension and retiree health and life benefits are as follows:


			Retiree
			Health and
	Pension		Life
Fiscal Year	Benefits		Benefits
2014		30,745		1,337
2015		12,968		1,270
2016		12,474		1,194
2017		11,033		1,111
2018		10,923		1,036
2019 through 2023		46,319		3,935

Estimated future pension benefit payments assumes that age 65 or older active and non-active eligible participants in the pension plan that had not received a benefit payment prior to fiscal ~~2013~~2014 will elect to receive a benefit payment in fiscal ~~2013.~~2014. In addition, for all periods presented, estimated future pension benefit payments assumes that participants will elect a lump sum payment in the fiscal year that the participant becomes eligible to receive benefits.

Effect on Operations. The following table provides the components of net periodic benefit costs included in operating expenses for fiscal 2013, 2012 ~~2011~~ and ~~2010:~~2011:


	Pension Benefits									Retiree Health and Life Benefits									Pension Benefits									Retiree Health and Life Benefits
	2012			2011			2010			2012			2011			2010			2013			2012			2011			2013			2012			2011
Service cost	$	—		$	—		$	—		$	7		$	7		$	7		$	—		$	—		$	—		$	8		$	7		$	7
Interest cost		6,311			6,822			7,503			802			855			1,013			5,229			6,311			6,822			586			802			855
Expected return on plan assets		(5,665	)		(6,295	)		(8,080	)		—			—			—			(5,281	)		(5,665	)		(6,295	)		—			—			—
Amortization of prior service credit		—			—			—			(490	)		(490	)		(490	)		—			—			—			(490	)		(490	)		(490	)
Settlement charge		—			—			2,818			—			—			—
Recognized net actuarial loss		5,271			4,721			5,374			—			(35	)		(65	)		5,285			5,271			4,721			—			—			(35	)

Net periodic benefit costs	$	5,917		$	5,248		$	7,615		$	319		$	337		$	465		$	5,233		$	5,917		$	5,248		$	104		$	319		$	337

During fiscal 2012 and fiscal 2011, the amount of the pension benefit obligation settled through lump sum payments did not exceed the settlement threshold (combined service and interest costs of net periodic pension cost); therefore, a settlement charge was not required to be recognized in either of those fiscal years. During fiscal 2010, lump sum pension settlement payments to either terminated or retired individuals amounted to $7,889, which exceeded the settlement threshold of $7,503 for fiscal 2010, and as a result, the Partnership was required to recognize a non-cash settlement charge of $2,818 during fiscal 2010. The non-cash charge was required to accelerate recognition of a portion of cumulative unamortized losses in the defined benefit pension plan.

Actuarial Assumptions. The assumptions used in the measurement of the Partnership’s benefit obligations as of September ~~29, 2012~~28, 2013 and September ~~24, 2011~~29, 2012 are shown in the following table:


	Pension Benefits						Retiree Health and Life Benefits						Pension Benefits						Retiree Health and Life Benefits
	2012			2011			2012			2011			2013			2012			2013			2012
Weighted-average discount rate		3.500	%		4.375	%		3.000	%		4.000	%		4.375	%		3.500	%		3.750	%		3.000	%
Average rate of compensation increase		n/a			n/a			n/a			n/a			n/a			n/a			n/a			n/a
Health care cost trend		n/a			n/a			7.530	%		7.740	%		n/a			n/a			7.330	%		7.530	%

The assumptions used in the measurement of net periodic pension benefit and postretirement benefit costs for fiscal 2013, 2012 ~~2011~~ and ~~2010~~2011 are shown in the following table:


	Pension Benefits									Retiree Health and Life Benefits									Pension Benefits									Retiree Health and Life Benefits
	2012			2011			2010			2012			2011			2010			2013			2012			2011			2013			2012			2011
Weighted-average discount rate		4.375	%		4.750	%		5.125	%		4.000	%		4.250	%		5.000	%		3.500	%		4.375	%		4.750	%		3.000	%		4.000	%		4.250	%
Average rate of compensation increase		n/a			n/a			n/a			n/a			n/a			n/a			n/a			n/a			n/a			n/a			n/a			n/a
Weighted-average expected long- term rate of return on plan assets		4.800	%		5.000	%		6.250	%		n/a			n/a			n/a
Weighted-average expected long-term rate of return on plan assets																				4.500	%		4.800	%		5.000	%		n/a			n/a			n/a
Health care cost trend		n/a			n/a			n/a			7.740	%		7.950	%		8.150	%		n/a			n/a			n/a			7.530	%		7.740	%		7.950	%

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 ~~7.53%~~7.33% increase in health care costs assumed at September ~~29, 2012~~28, 2013 is assumed to decrease gradually to 4.48% in fiscal 2028 and to remain at that level thereafter. An increase or decrease of the assumed health care cost trend rates by 1.0% in each year would have no material impact to the Partnership’s benefit obligation as of September ~~29, 2012~~28, 2013 nor the aggregate of service and interest components of net periodic postretirement benefit expense for fiscal ~~2012.~~2013. The Partnership has concluded that the prescription drug benefits within the retiree medical plan do not entitle the Partnership to an available Medicare subsidy.

Multiemployer Pension Plans. As a result of the Inergy Propane Acquisition, the Partnership contributes to multiemployer pension plans (“MEPPs”) in accordance with various collective bargaining agreements covering union employees. As one of the many participating employers in these MEPPs, the Partnership is responsible with the other participating employers for any plan underfunding. During fiscal 2013, the Partnership established an accrual of $7,000 for its estimated obligation to certain MEPPs due to the Partnership’s voluntary partial withdrawal from one such MEPP and full withdrawal from four MEPPs. Due to the uncertainty regarding future factors that could trigger withdrawal liability, including the integration of Inergy Propane, the Partnership is unable to determine the amount and timing of any future withdrawal liability, if any.

The Partnership’s contributions to a particular MEPP are established by the applicable collective bargaining agreements (“CBAs”); however, the required contributions may increase based on the funded status of an MEPP and legal requirements of the Pension Protection Act of 2006 (the “PPA”), which requires substantially underfunded MEPPs to implement a funding improvement plan (“FIP”) or a rehabilitation plan (“RP”) to improve their funded status. Factors that could impact funded status of an MEPP include, without limitation, investment performance, changes in the participant demographics, decline in the number of contributing employers, changes in actuarial assumptions and the utilization of extended amortization provisions.

While no multiemployer pension plan that the Partnership contributed to is individually significant to the Partnership, the table below discloses the three largest MEPPs to which the Partnership contributes. The financial health of a MEPP is indicated by the zone status, as defined by the PPA, which represents the funded status of the plan as certified by the plan’s actuary. Plans in the red zone are less than 65% funded, the yellow zone are between 65% and 80% funded, and green zone are at least 80% funded. Total contributions made by the Partnership to multiemployer pension plans for the fiscal year ended September 28, 2013 are shown below and reflect contributions made from the Inergy Propane Acquisition Date.

EIN/

Contributions

Pension

greater than 5%

Plan

PPA Zone Status

FIP/RP

Contributions

of Total Plan

Expiration date

Pension Fund

Number

2013

2012

Status

2013

2012

Contributions

of CBA

New England Teamsters & Trucking
Industry Pension Fund

04-6372430

Red (a)

Implemented

562

March 2014 - April 2016

Local 282 Pension Trust Fund

11-6245313

Green (b)

n/a

284

September 2014

Teamsters Industrial Employees Pension Fund

22-6099363

Red (c)

Implemented

179

June 2017

Other (d)

137

n/a

1,162

159

Additionally, the Partnership contributes to certain multi-employer plans that provide health and welfare benefits and defined annuity plans. Contributions to those plans were $2,040 and $309 for fiscal 2013 and fiscal 2012, respectively.

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

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

The following summarizes the fair value of the Partnership’s derivative instruments and their location in the consolidated balance ~~sheet~~sheets as of September ~~29, 2012~~28, 2013 and September ~~24, 2011,~~29, 2012, respectively:


	As of September 29, 2012			As of September 24, 2011			As of September 28, 2013				As of September 29, 2012
	Location	Fair Value		Location	Fair Value		Location		Fair Value		Location		Fair Value
Asset Derivatives
Derivatives not designated as hedging instruments:
Commodity-related derivatives	Other current assets	$	4,523	Other current assets	$	4,842		Other current assets	$	2,546		Other current assets	$	4,523
	Other assets		610	Other assets		612		Other assets		716		Other assets		610

		$	5,133		$	5,454			$	3,262			$	5,133


	Location	Fair Value		Location	Fair Value		Location		Fair Value		Location		Fair Value
Liability Derivatives
Derivatives designated as hedging instruments:
Interest rate swaps	Other current liabilities	$	2,430	Other current liabilities	$	2,662		Other current liabilities	$	1,307		Other current liabilities	$	2,430
	Other liabilities		3,047	Other liabilities		1,934		Other liabilities		1,121		Other liabilities		3,047

		$	5,477		$	4,596			$	2,428			$	5,477

Derivatives not designated as hedging instruments:
Commodity-related derivatives	Other current liabilities	$	8,720	Other current liabilities	$	2,407		Other current liabilities	$	430		Other current liabilities	$	8,720
	Other liabilities		22	Other liabilities		69		Other liabilities		—		Other liabilities		22

		$	8,742		$	2,476			$	430			$	8,742

On August 1, 2012, the Partnership executed swap agreements with a notional amount of 44,531 propane gallons to hedge exposures to fluctuations in propane prices attributable to the same number of propane gallons committed to be sold to customers at fixed prices. The fixed price sales arrangements were assumed in the Inergy Propane Acquisition.

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


													Fair Value Measurement Using Significant
	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)												Unobservable Inputs (Level 3)
	Fiscal 2012						Fiscal 2011						Fiscal 2013						Fiscal 2012
	Assets			Liabilities			Assets			Liabilities			Assets			Liabilities			Assets			Liabilities
Beginning balance of over-the-counter options	$	1,780		$	118		$	1,509		$	30		$	5,002		$	1,209		$	1,780		$	118
Beginning balance realized during the period		(1,168	)		(49	)		(1,509	)		(30	)		(4,400	)		(1,182	)		(1,168	)		(49	)
Change in the fair value of beginning balance		1,059			120			—			—			(580	)		(27	)		1,059			120
Contracts purchased during the period		3,331			1,020			1,780			118			1,825			—			3,331			1,020

Ending balance of over-the-counter options	$	5,002		$	1,209		$	1,780		$	118		$	1,847		$	—		$	5,002		$	1,209

As of September ~~29, 2012~~28, 2013 and September ~~24, 2011,~~29, 2012, the Partnership’s outstanding commodity-related derivatives had a weighted average maturity of approximately 45 months.

The effect of the Partnership’s derivative instruments on the consolidated ~~statement~~statements of operations for fiscal 2013, 2012 ~~2011~~ and ~~2010~~2011 are as follows:


								Amount of Gains			Gains (Losses) Reclassified from
								(Losses) Recognized in			Accumulated OCI into Income
	Amount of Gains (Losses) Recognized in OCI (Effective Portion)			Gains (Losses) Reclassified from Accumulated OCI into Income (Effective Portion)				OCI (Effective			(Effective Portion)
Derivatives in Cash Flow Hedging Relationships:				Location	Amount			Portion)			Location	Amount
Fiscal 2013
Interest rate swap								$	584		Interest expense	$	(2,465	)

Fiscal 2012
Interest rate swap	$	(3,561	)	Interest expense	$	(2,680	)	$	(3,561	)	Interest expense	$	(2,680	)

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

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

												Amount of
												Unrealized
								Location of Gains				Gains (Losses)
								(Losses) Recognized in				Recognized in
Derivatives Not Designated as Hedging Instruments:								Income				Income
Fiscal 2013
Commodity-related derivatives									Cost of products sold			$	(4,318	)

Fiscal 2012
Commodity-related derivatives									Cost of products sold			$	4,649

Fiscal 2011
Commodity-related derivatives									Cost of products sold			$	1,431

Concentrations. The Partnership’s principal customers are residential and commercial end users of propane and fuel oil and refined fuels served by approximately 750 locations in 41 states. No single customer accounted for more than 10% of revenues during fiscal 2013, 2012 ~~2011~~ or ~~2010~~2011 and no concentration of receivables exists as of September ~~29, 2012~~28, 2013 or September ~~24, 2011.~~29, 2012.

During fiscal ~~2012, Targa Liquids Marketing and Trade, Enterprise Products Operating L.P., Phillips 66 and~~2013, Inergy Services (a subsidiary of Inergy) ~~accounted for 16%, 13%, 11%~~ and ~~11%, respectively,~~Targa Liquids Marketing and Trade (“Targa”) provided approximately 34% and 12% of ~~the Partnership’s~~our total propane ~~purchases.~~purchases, respectively. No other single supplier accounted for more than 10% of the Partnership’s propane purchases in fiscal ~~2012.~~2013. The Partnership believes that, if supplies from any of these suppliers were interrupted, it would be able to secure adequate propane supplies from other sources without a material disruption of its operations.

Credit Risk. Exchange-traded futures and options contracts are traded on and guaranteed by the NYMEX and as a result, have minimal credit risk. Futures contracts traded with brokers of the NYMEX require daily cash settlements in margin accounts. The Partnership is subject to credit risk with over-the-counter swaps and options contracts entered into with various third parties to the extent the counterparties do not perform. The Partnership evaluates the financial condition of each counterparty with which it conducts business and establishes credit limits to reduce exposure to credit risk based on non-performance. The Partnership does not require collateral to support the contracts.

Bank Debt and Senior Notes. The fair value of the Revolving Credit Facility approximates the carrying value since the interest rates are adjusted quarterly to reflect market conditions. Based upon quoted market prices, the fair value of the Partnership’s 2018 Senior Notes, 2020 Senior Notes and 2021 Senior Notes was ~~$531,316, $272,500~~$533,799, $268,125 and ~~$542,460,~~$372,143, respectively, as of September ~~29, 2012.~~28, 2013.

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 $33,036, $23,593 ~~$18,868~~ and ~~$17,561~~$18,868 for fiscal 2013, 2012 and 2011, ~~and 2010,~~ respectively.

Future minimum rental commitments under noncancelable operating lease agreements as of September ~~29, 2012~~28, 2013 are as follows:


	Minimum		Minimum
	Lease		Lease
Fiscal Year	Payments		Payments
2013	$	28,254
2014		23,848		27,238
2015		17,396		20,488
2016		10,188		12,770
2017		6,012		7,894
2018 and thereafter		7,306
2018				5,208
2019 and thereafter				5,947

Self Insurance.As described in Note 2, the Partnership is self-insured for general and product, workers’ compensation and automobile liabilities up to predetermined amounts above which third party insurance applies. At September ~~29, 2012~~28, 2013 and September ~~24, 2011,~~29, 2012, the Partnership had accrued liabilities of ~~$54,551~~$58,152 and ~~$52,841,~~$54,551, respectively, representing the total estimated losses under these self-insurance programs. For the portion of the estimated liability that exceeds insurance deductibles, the Partnership records an asset within other assets (or prepaid expenses and other current assets, as applicable) related to the amount of the liability expected to be covered by insurance which amounted to ~~$17,522~~$18,330 and ~~$17,513~~$17,522 as of September 28, 2013 and September 29, 2012, ~~and September 24, 2011,~~ respectively.

Legal Matters.The Partnership’s operations are subject to operating hazards and risks normally incidental to handling, storing and delivering combustible liquids such as propane. The Partnership has been, and will continue to be, a defendant in various legal proceedings and litigation as a result of these operating hazards and risks, and as a result of other aspects of its business. In this last regard, the Partnership currently is a defendant in suits in two states, including one class action and another putative class action in which the court has denied class certification without prejudice. The Partnership believes both such suits are without merit. The class action alleges several claims relating to two fees charged by the Partnership in connection with its residential propane business in California. During the fourth quarter of fiscal 2012, the Partnership entered into an agreement to settle ~~that~~a California action, in which were alleged several claims relating to two fees charged by the Partnership, on a classwide basis in return for the payment of a monetary sum and certain non-monetary consideration, and established an accrual of $4,500 for the estimated cost of the settlement. ~~The~~This settlement, entered into to avoid both the continued expenses and burden of defending that action and the uncertainty inherent in all litigation, was approved by the trial court ~~granted preliminary approval~~in May 2013, and the Partnership completed distribution of the ~~proposed~~ settlement ~~on November 19, 2012.~~proceeds to the class members in the fourth quarter of fiscal 2013. The Partnership is currently a defendant in a putative class action in which the court has denied class certification without prejudice. The Partnership believes such suit is without merit. In the putative class action, the Partnership has been successful in eliminating several of the claims such that only certain contractual and consumer statute claims remain. The subject matter jurisdiction of the court to adjudicate certain of the contractual claims is on appeal. The Partnership is contesting this putative class action vigorously and has determined, based on the allegations and discovery to date, that no reserve for a loss contingency other than for legal defense fees and expenses is required.

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 ~~2019.~~2020. 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, was ~~$17,990~~$16,312 as of September ~~29, 2012.~~28, 2013. The fair value of residual value guarantees for outstanding operating leases was de minimis as of September ~~29, 2012~~28, 2013 and September ~~24, 2011.~~29, 2012.

On ~~August 14, 2012,~~May 17, 2013, the Partnership sold ~~6,300,000~~2,700,000 Common Units in a public offering at a price of ~~$37.61~~$48.16 per Common Unit, realizing proceeds of ~~$225,722,~~$124,684, net of underwriting commissions and other offering expenses. ~~Also on August 14, 2012, the Partnership used the net proceeds from the offering to repay its borrowings of $225,000 on August 1, 2012 under its 364-Day Facility.~~ On ~~August 20, 2012,~~May 22, 2013, following the underwriters’ exercise of their over-allotment option, the Partnership sold an additional ~~945,000~~405,000 Common Units at ~~$37.61~~$48.16 per Common Unit, generating additional ~~net~~ proceeds of ~~$34,120,~~$18,760, net of underwriting commissions. The net proceeds from the offering, including the net proceeds from the underwriters’ exercise of their over-allotment option, were used to redeem $133,400 of the Partnership’s 2021 Senior Notes in August 2013.

The Partnership manages and evaluates its operations in five operating segments, three of which are reportable segments: Propane, Fuel Oil and Refined Fuels and Natural Gas and Electricity. The chief operating decision maker evaluates performance of the operating segments using a number of performance measures, including gross margins and income before interest expense and provision for income taxes (operating profit). Costs excluded from these profit measures are captured in Corporate and include corporate overhead expenses not allocated to the operating segments. Unallocated corporate overhead expenses include all costs of back office support functions that are reported as general and administrative expenses within the consolidated statements of operations. In addition, certain costs associated with field operations support that are reported in operating expenses within the consolidated statements of operations, including purchasing, training and safety, are not allocated to the individual operating segments. Thus, operating profit for each operating segment includes only the costs that are directly attributable to the operations of the individual segment. The accounting policies of the operating segments are otherwise the same as those described in the summary of significant accounting policies in Note 2.

The propane segment is primarily engaged in the retail distribution of propane to residential, commercial, industrial and agricultural customers and, to a lesser extent, wholesale distribution to large industrial end users. In the residential and commercial markets, propane is used primarily for space heating, water heating, cooking and clothes drying. Industrial customers use propane generally as a motor fuel burned in internal combustion engines that power over-the-road vehicles, forklifts and stationary engines, to fire furnaces and as a cutting gas. In the agricultural markets, propane is primarily used for tobacco curing, crop drying, poultry brooding and weed control.

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 service 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.

The following table presents certain data by reportable segment and provides a reconciliation of total operating segment information to the corresponding consolidated amounts for the periods presented:


	Year Ended									Year Ended
	September 29,			September 24,			September 25,			September 28,			September 29,			September 24,
	2012			2011			2010			2013			2012			2011
Revenues:
Propane	$	843,648		$	929,492		$	885,459		$	1,357,103		$	843,648		$	929,492
Fuel oil and refined fuels		114,288			139,572			135,059			208,957			114,288			139,572
Natural gas and electricity		67,419			84,721			77,587			79,432			67,419			84,721
All other		38,103			36,767			38,589			58,114			38,103			36,767

Total revenues	$	1,063,458		$	1,190,552		$	1,136,694		$	1,703,606		$	1,063,458		$	1,190,552


Operating income:
Propane	$	143,789		$	203,567		$	230,717		$	287,473		$	142,548		$	203,567
Fuel oil and refined fuels		887			11,140			11,589			(2,799	)		890			11,140
Natural gas and electricity		6,991			11,667			11,629			11,565			6,991			11,667
All other		(17,233	)		(13,750	)		(17,995	)		(26,483	)		(17,239	)		(13,750	)
Corporate		(91,533	)		(69,396	)		(82,572	)		(92,780	)		(91,533	)		(69,396	)

Total operating income		42,901			143,228			153,368			176,976			41,657			143,228
Reconciliation to net income:
Loss on debt extinguishment		2,249			—			9,473			2,144			2,249			—
Interest expense, net		38,633			27,378			27,397			95,427			38,633			27,378
Provision for income taxes		137			884			1,182			607			137			884

Net income	$	1,882		$	114,966		$	115,316		$	78,798		$	638		$	114,966


Depreciation and amortization:
Propane	$	33,585		$	19,525		$	17,505		$	104,533		$	34,826		$	19,525
Fuel oil and refined fuels		3,655			4,139			3,277			4,634			3,652			4,139
Natural gas and electricity		464			897			970			198			464			897
All other		339			111			261			638			345			111
Corporate		7,747			10,956			8,821			20,381			7,747			10,956

Total depreciation and amortization	$	45,790		$	35,628		$	30,834		$	130,384		$	47,034		$	35,628


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


		Page

	PART I

ITEM 1.	BUSINESS		1
ITEM 1A.	RISK FACTORS		10
ITEM 1B.	UNRESOLVED STAFF COMMENTS		22
ITEM 2.	PROPERTIES		22
ITEM 3.	LEGAL PROCEEDINGS		23
ITEM 4.	MINE SAFETY DISCLOSURES		23

	PART II

ITEM 5.	MARKET FOR THE REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF UNITS		24
ITEM 6.	SELECTED FINANCIAL DATA		25
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		28
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		4849
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA		5052
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE		5355
ITEM 9A.	CONTROLS AND PROCEDURES		5355
ITEM 9B.	OTHER INFORMATION		5456

	PART III

ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND PARTNERSHIP GOVERNANCE		5557
ITEM 11.	EXECUTIVE COMPENSATION		6163
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS		85
~~ITEM 13.~~	~~CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE~~		87
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE		89
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES		8890

	PART IV

ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES		8991

SIGNATURES			9092


~~Fiscal 2012, 2011 and 2010 LTIP Award Peer Group~~
~~Peer Group Member Name~~		~~Ticker Symbol~~
~~AmeriGas Partners, L.P.~~		~~APU~~
~~Copano Energy, LLC~~		~~CPNO~~
~~Dorchester Minerals, L.P.~~		~~DMLP~~
~~Enbridge Energy Partners, L.P.~~		~~EEP~~
~~Energy Transfer Partners, L.P.~~		~~ETP~~
~~Ferrellgas Partners, L.P.~~		~~FGP~~
~~Global Partners, L.P.~~		~~GLP~~
~~Inergy, L.P.~~		~~NRGY~~
~~MarkWest Energy Partners, L.P.~~		~~MWE~~
~~Plains All American Pipeline, L.P.~~		~~PAA~~
~~Sunoco Logistics Partners, L.P.~~		~~SXL~~


Title of each class		Name of each exchange on which registered
Common Units		New York Stock Exchange


Documents Incorporated by Reference: None		Total number of pages (excluding Exhibits): ~~133~~138


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

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


Name	Age			Position With the Partnership
Michael J. Dunn, Jr.		63	64		President and Chief Executive Officer; Member of the Board of Supervisors
Michael A. Stivala		43	44		Chief Financial Officer
Michael M. Keating		59	60		Senior Vice President -– Administration
A. Davin D’Ambrosio		48	49		Vice President and Treasurer
Paul Abel		59	60		Vice President, General Counsel and Secretary
Steven C. Boyd		48	49		Vice President – Field Operations
Douglas T. Brinkworth		51	52		Vice President – Product Supply
~~Neil Scanlon~~ Michael Kuglin		4743		Vice President and Chief Accounting Officer
Neil Scanlon	48		Vice President – Information Services
Mark Wienberg		50	51		Vice President – Operational Support and Analysis
~~Michael Kuglin~~ Sandra N. Zwickel		42	47		Vice President ~~and Chief Accounting Officer~~– Human Resources
Harold R. Logan, Jr.		68	69		Member of the Board of Supervisors (Chairman)
John Hoyt Stookey		82	83		Member of the Board of Supervisors (Chairman of the Compensation Committee)
Dudley C. Mecum		77	78		Member of the Board of Supervisors
John D. Collins		74	75		Member of the Board of Supervisors (Chairman of the Audit Committee)
Jane Swift		47	48		Member of the Board of Supervisors
Lawrence C. Caldwell		66	67		Member of the Board of Supervisors
Matthew J. Chanin		58	59		Member of the Board of Supervisors


Hypothetical Fiscal 2012 Cash Bonus Plan EBITDA Results (in Millions)	Hypothetical Fiscal 2012 Cash Bonus Plan EBITDA Expressed as a Percentage of Budgeted Cash Bonus Plan EBITDA	Target Bonus Percentage that would have been Earned if Actual Cash Bonus Plan EBITDA Equaled the Figure in the First Column
$224.4	120%	120%
$205.7	110%	110%
$187.0⁽¹⁾	100%	100%
$177.7	95%	90%
$168.3	90%	60%


Hypothetical Fiscal 2013 Cash Bonus Plan EBITDA Results (in Millions)	Hypothetical Fiscal 2013 Cash Bonus Plan EBITDA Expressed as a Percentage of Budgeted Cash Bonus Plan EBITDA	Target Bonus Percentage that would have been Earned if Actual Cash Bonus Plan EBITDA Equaled the Figure in the First Column
$438.0	120%	120%
$401.5	110%	110%
$365.0⁽¹⁾	100%	100%
$346.8	95%	90%
$328.5	90%	60%


	Fiscal		Fiscal
	2013 Award		2012 Award
Michael J. Dunn, Jr.		6,559		5,258
Michael A. Stivala		3,180		2,435
Steven C. Boyd		3,074		2,391
Mark Wienberg		2,968		2,214
Douglas T. Brinkworth		2,862		2,169


	Fiscal
	2014 Award
Michael J. Dunn, Jr.		5,404
Michael A. Stivala		2,620
Steven C. Boyd		2,533
Mark Wienberg		2,445
Douglas T. Brinkworth		2,358


	Fiscal 2012 Award		Fiscal 2011 Award
Michael J. Dunn, Jr.		5,258		4,787
Michael A. Stivala		2,435		2,217
Steven C. Boyd		2,391		2,177
Mark Wienberg		2,214		2,016
Douglas T. Brinkworth		2,169		1,975


	~~Fiscal~~ ~~2013 Award~~
~~Michael J. Dunn, Jr.~~		~~6,559~~
~~Michael A. Stivala~~		~~3,180~~
~~Steven C. Boyd~~		~~3,074~~
~~Mark Wienberg~~		~~2,968~~
~~Douglas T. Brinkworth~~		~~2,862~~


~~Fiscal 2013 LTIP Award Peer Group~~
Peer Group Member Name		Ticker Symbol

AmeriGas Partners, L.P.		APU
Copano Energy, LLC⁽¹⁾		CPNO
Dorchester Minerals, L.P.		DMLP
Enbridge Energy Partners, L.P.		EEP
Energy Transfer Partners, L.P.		ETP
Ferrellgas Partners, L.P.		FGP
Global Partners, L.P.		GLP
Inergy, L.P.⁽²⁾		NRGY
MarkWest Energy Partners, L.P.		MWE
Plains All American Pipeline, L.P.		PAA
Sunoco Logistics Partners, L.P.		SXL

Fiscal 2013 Award Peer Group
Peer Group Member Name		Ticker Symbol

Atlas Pipeline Partners, L.P.		APL
AmeriGas Partners, L.P.		APU
BreitBurn Energy Partners, L.P.		BBEP
Copano Energy, ~~L.L.C.~~LLC⁽¹⁾		CPNO
Enbridge Energy Partners, L.P.		EEP
Ferrellgas Partners, L.P.		FGP
Genesis Energy, L.P.		GEL
Global Partners L.P.		GLP
Inergy Midstream, L.P.⁽²⁾		NRGM
MarkWest Energy Partners, L.P.		MWE
TC Pipelines, L.P.		TCP


Distribution Coverage Ratio	% of Unvested LTIP Units That Will Vest
Less than 1.00		00.0	%
1.00 (Threshold Performance)		50.0	%
1.01		52.5	%
1.02		55.0	%
1.03		57.5	%
1.04		60.0	%
1.05		62.5	%
1.06		65.0	%
1.07		67.5	%
1.08		70.0	%
1.09		72.5	%
1.10		75.0	%
1.11		77.5	%
1.12		80.0	%
1.13		82.5	%
1.14		85.0	%
1.15		87.5	%
1.16		90.0	%
1.17		92.5	%
1.18		95.0	%
1.19		97.5	%
1.20 (Target Performance)		100.0	%
1.21		101.7	%
1.22		103.3	%
1.23		105.0	%
1.24		106.7	%
1.25		108.4	%
1.26		110.0	%
1.27		111.7	%
1.28		113.4	%
1.29		115.0	%
1.30		116.7	%
1.31		118.4	%
1.32		120.0	%
1.33		121.7	%
1.34		123.4	%
1.35		125.1	%
1.36		126.7	%
1.37		128.4	%
1.38		130.1	%
1.39		131.7	%
1.40		133.4	%
1.41		135.1	%
1.42		136.7	%
1.43		138.4	%
1.44		140.1	%
1.45		141.8	%
1.46		143.4	%
1.47		145.1	%
1.48		146.8	%
1.49		148.4	%
1.50 and Higher (Maximum Performance)		150.0	%


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


If We Meet This Percentage of Budgeted EBITDA⁽¹⁾…	The Participating Employee Will Receive this Matching Contribution for the ~~Year…~~Year
115% or higher	~~100%~~	100	%
100% to 114%	~~50%~~	50	%
90% to 99%	~~25%~~	25	%
Less than 90%	0%	0	%


	~~Amount and Nature of~~	~~Percent~~
~~Name of Beneficial Owner~~	~~Beneficial Ownership (1)~~	~~of Class~~
~~Michael J. Dunn, Jr. (a)~~	~~108,888~~		*
~~Michael A. Stivala (b)~~	~~18,150~~		*
~~Steven C. Boyd (c)~~	~~24,233~~		*
~~Mark Wienberg (d)~~	~~9,343~~		*
~~Douglas T. Brinkworth (e)~~	~~25,675~~		*

~~John Hoyt Stookey (f)~~	~~7,566~~		*
~~Harold R. Logan, Jr.(f)~~	~~17,387~~		*
~~Dudley C. Mecum (f)~~	~~17,134~~		*
~~Jane Swift (f)~~	~~2,748~~		*
~~John D. Collins (g)~~	~~17,946~~		*
~~Lawrence C. Caldwell (h)~~	~~15,963~~		*
~~Matthew J. Chanin (i)~~	~~3,000~~		*

~~All Members of the Board of Supervisors and Executive Officers,as a Group (17 persons) (j)~~	~~316,994~~		*


	Amount and Nature of		Percent
Name of Beneficial Owner	Beneficial Ownership (1)		of Class (2)
Neuberger Berman Group LLC (a)		5,836,777		9.7	%
Michael J. Dunn, Jr. (b)		108,888		*
Michael A. Stivala (c)		15,044		*
Steven C. Boyd (d)		19,873		*
Mark Wienberg (e)		4,242		*
Douglas T. Brinkworth (f)		21,310		*
John Hoyt Stookey (g)		8,466		*
Harold R. Logan, Jr.(g)		11,840		*
Dudley C. Mecum (g)		18,034		*
Jane Swift (h)		900		*
John D. Collins (g)		16,346		*
Lawrence C. Caldwell (i)		15,963		*
Matthew J. Chanin (j)		5,000		*
All Members of the Board of Supervisors and Executive
Officers, as a Group (18 persons) (k)		310,059		*


	SUBURBAN PROPANE PARTNERS, L.P.

Date: November ~~28, 2012~~27, 2013	By:	/s/ MICHAEL J. DUNN, JR.

		Michael J. Dunn, Jr.
		President, Chief Executive Officer and
		Supervisor


		Signature	Title	Date

By:	/s/ MICHAEL J. DUNN, JR.	President, Chief Executive	November ~~28, 2012~~27, 2013
	(Michael J. Dunn, Jr.)	Officer and Supervisor

By:	/s/ HAROLD R. LOGAN, JR.	Chairman and Supervisor	November ~~28, 2012~~27, 2013
	(Harold R. Logan, Jr.)

By:	/s/ JOHN HOYT STOOKEY	Supervisor	November ~~28, 2012~~27, 2013
	(John Hoyt Stookey)

By:	/s/ DUDLEY C. MECUM	Supervisor	November ~~28, 2012~~27, 2013
	(Dudley C. Mecum)

By:	/s/ JOHN D. COLLINS	Supervisor	November ~~28, 2012~~27, 2013
	(John D. Collins)

By:	/s/ JANE SWIFT	Supervisor	November ~~28, 2012~~27, 2013
	(Jane Swift)

By:	/s/ LAWRENCE C. CALDWELL	Supervisor	November ~~28, 2012~~27, 2013
	(Lawrence C. Caldwell)

By	/s/ MATTHEW J. CHANIN	Supervisor	November ~~28, 2012~~27, 2013
	(Matthew J. Chanin)

By:	/s/ MICHAEL A. STIVALA	Chief Financial Officer	November ~~28, 2012~~27, 2013
	(Michael A. Stivala)

By	/s/ MICHAEL A. KUGLIN	Vice President and	November ~~28, 2012~~27, 2013
	(Michael A. Kuglin)	Chief Accounting Officer


Exhibit Number		Description

2.1		Contribution Agreement dated as of April 25, 2012, as amended as of June 15, 2012, July 6, 2012 and July 19, 2012, among Inergy, L.P., Inergy GP, LLC, Inergy Sales and Service, Inc. and Suburban Propane Partners, L.P. (Incorporated by reference to Exhibit 2.1 to the Partnership’s Current Reports on Form 8-K filed April 26, 2012, June 15, 2012, July 6, 2012 and July 19, 2012, respectively).

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

3.2		Third Amended and Restated Agreement of Limited Partnership of the Operating Partnership dated as of October 19, 2006, as amended as of June 24, 2009. (Incorporated by reference to Exhibit 10.2 to the Partnership’s Current Report on Form 8-K filed June 30, 2009).

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

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

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

~~4.4~~ 4.2		Indenture, dated as of March 23, 2010, related to the 7.375% Senior Notes due 2020, by and among Suburban Propane Partners, L.P., Suburban Energy Finance Corp. and The Bank of New York Mellon, as Trustee, including the form of 7.375% Senior Notes due 2020. (Incorporated by reference to Exhibit 4.1 to the Partnership’s Current Report on Form 8-K filed March 23, 2010).

~~4.5~~ 4.3		First Supplemental Indenture, dated as of March 23, 2010, related to the 7.375% Senior Notes due 2020, by and among Suburban Propane Partners, L.P., Suburban Energy Finance Corp. and The Bank of New York Mellon, as Trustee. (Incorporated by reference to Exhibit 4.2 to the Partnership’s Current Report on Form 8-K filed March 23, 2010).

~~4.6~~ 4.4		Indenture, dated as of August 1, 2012, related to the 7.5% Senior Notes due 2018 and the 7.375% Senior Notes due 2021, by and among Suburban Propane Partners, L.P., Suburban Energy Finance Corp. and The Bank of New York Mellon, as Trustee, including the form of 7.5% Senior Notes due 2018 and the form of 7.375% Senior Notes due 2021. (Incorporated by reference to Exhibit 4.1 to the Partnership’s Current Report on Form 8-K filed August 2, 2012).

~~4.7~~		Registration Rights Agreement, dated August 1, 2012, by and among Suburban Propane Partners, L.P., Suburban Energy Finance Corporation, Evercore Group L.L.C. and Citigroup Global Markets Inc. (Incorporated by reference to Exhibit 4.2 to the Partnership’s Registration Statement on Form S-4 dated September 19, 2012).


	Page

Report of Independent Registered Public Accounting Firm		F-2

Consolidated Balance Sheets – As of September ~~29, 2012~~28, 2013 and September ~~24, 2011~~29, 2012		F-3

Consolidated Statements of Operations – Years Ended September 28, 2013, September 29, 2012 and September 24, 2011 ~~and September 25, 2010~~		F-4

Consolidated Statements of ~~Cash Flows~~Comprehensive Income – Years Ended September 28, 2013, September 29, 2012 and September 24, 2011 ~~and September 25, 2010~~		F-5

Consolidated Statements of ~~Partners’ Capital~~Cash Flows – Years Ended September 28, 2013, September 29, 2012 and September 24, 2011 ~~and September 25, 2010~~		F-6

~~Notes to~~ Consolidated ~~Financial~~ Statements of Partners’ Capital – Years Ended September 28, 2013, September 29, 2012 and September 24, 2011		F-7

Notes to Consolidated Financial Statements		F-8


	Number of Common Units		Common Unitholders			Accumulated Other Comprehensive (Loss) Income			Total Partners’ Capital			Comprehensive Income (Loss)
Balance at September 26, 2009		35,228	$	418,824		$	(61,288	)	$	357,536
Net income				115,316						115,316		$	115,316
Other comprehensive income:
Net unrealized losses on cash flow hedges							(5,706	)		(5,706	)		(5,706	)
Reclassification of realized losses on cash flow hedges into earnings							3,597			3,597			3,597
Amortization of net actuarial losses and prior service credits into earnings and net change in funded status of benefit plans							3,353			3,353			3,353
Recognition in earnings of net actuarial loss for pension settlement							2,818			2,818			2,818

Total comprehensive income												$	119,378

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

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

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

Total comprehensive income												$	112,276

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

Balance at September 24, 2011		35,429	$	418,134		$	(59,916	)	$	358,218
Net income				1,882						1,882		$	1,882
Other comprehensive income:
Net unrealized losses on cash flow hedges							(3,561	)		(3,561	)		(3,561	)
Reclassification of realized losses on cash flow hedges into earnings							2,680			2,680			2,680
Amortization of net actuarial losses and prior service credits into earnings and net change in funded status of benefit plans							(310	)		(310	)		(310	)

Total comprehensive income												$	691

Partnership distributions				(121,094	)					(121,094	)
Issuance of Common Units for business acquisition		14,200		590,027						590,027
Sale of Common Units under public offering, net of offering expenses		7,245		259,842						259,842
Common Units issued under
Restricted Unit Plans		139
Compensation cost recognized under
Restricted Unit Plans, net of forfeitures				4,059						4,059

Balance at September 29, 2012		57,013		1,152,850		$	(61,107	)	$	1,091,743


	Number of Common Units		Common Unitholders			Accumulated Other Compre- hensive (Loss) Income			Total Partners’ Capital
Balance at September 25, 2010		35,318	$	419,882		$	(57,226	)	$	362,656
Net income				114,966						114,966
Net unrealized losses on cash flow hedges							(1,177	)		(1,177	)
Reclassification of realized losses on cash flow hedges into earnings							2,881			2,881
Amortization of net actuarial losses and prior service credits into earnings and net change in funded status of benefit plans							(4,394	)		(4,394	)
Partnership distributions				(120,636	)					(120,636	)
Common Units issued under Restricted Unit Plans		111
Compensation cost recognized under Restricted Unit Plans, net of forfeitures				3,922						3,922

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

Net income				638						638
Net unrealized losses on cash flow hedges							(3,561	)		(3,561	)
Reclassification of realized losses on cash flow hedges into earnings							2,680			2,680
Amortization of net actuarial losses and prior service credits into earnings and net change in funded status of benefit plans							(310	)		(310	)
Partnership distributions				(121,094	)					(121,094	)
Issuance of Common Units for business acquisition		14,200		590,027						590,027
Sale of Common Units under public offering, net of offering expenses		7,245		259,842						259,842
Common Units issued under Restricted Unit Plans		139
Compensation cost recognized under Restricted Unit Plans, net of forfeitures				4,059						4,059

Balance at September 29, 2012		57,013	$	1,151,606		$	(61,107	)	$	1,090,499

Net income				78,798						78,798
Net unrealized gains on cash flow hedges							584			584
Reclassification of realized losses on cash flow hedges into earnings							2,465			2,465
Amortization of net actuarial losses and prior service credits into earnings and net change in funded status of benefit plans							10,705			10,705
Partnership distributions				(201,257	)					(201,257	)
Sale of Common Units under public offering, net of offering expenses		3,105		143,444						143,444
Common Units issued under Restricted Unit Plans		113
Compensation cost recognized under Restricted Unit Plans, net of forfeitures				3,888						3,888

Balance at September 28, 2013		60,231	$	1,176,479		$	(47,353	)	$	1,129,126


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


Assets acquired:
Cash and cash equivalents	$	7,964
Accounts receivable		36,076
Inventories		30,457
Other current assets		2,067

Current assets acquired		76,564
Property, plant & equipment		617,854
Customer relationships (estimated useful life of 9 years)		445,500
Non-compete agreements (estimated useful life of 6 years)		23,059
Other intangible assets (estimated useful life of 4 years)		1,983
Goodwill		809,778
Other assets		2,151

Total assets acquired	$	1,976,889

Liabilities assumed:
Accounts payable	$	16
Accrued employment and benefit costs		2,149
Customer deposits and advances		48,469
Other current liabilities		18,613
Other noncurrent liabilities		16,727

Total liabilities assumed		85,974

Total	$	1,890,915


Fiscal Year	Pension Benefits		Retiree Health and Life Benefits
2013	$	30,486	$	1,427
2014		13,702		1,369
2015		12,695		1,301
2016		12,384		1,224
2017		11,188		1,141
2018 through 2022		49,163		4,483


Derivatives Not Designated as Hedging Instruments:	Location of Gains (Losses) Recognized in Income	Amount of Unrealized Gains (Losses) Recognized in Income
Fiscal 2012
Commodity-related derivatives	Cost of products sold	$	4,649

		$	4,649

Fiscal 2011
Commodity-related derivatives	Cost of products sold	$	1,431

		$	1,431

Fiscal 2010
Commodity-related derivatives	Cost of products sold	$	(5,400	)

		$	(5,400	)


		Page
Schedule II	Valuation and Qualifying ~~Accounts—~~Accounts– Years Ended September 28,2013, September 29, 2012 and September 24, 2011 ~~and September 25, 2010~~		S-2


	Balance at		Charged								Balance		Balance at		Charged								Balance
	Beginning		(credited) to Costs			Other					at End		Beginning		(credited) to Costs			Other					at End
	of Period		and Expenses			Additions		Deductions (a)			of Period		of Period		and Expenses			Additions		Deductions (a)			of Period
Year Ended September 25, 2010

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

Year Ended September 24, 2011

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

Year Ended September 29, 2012

Allowance for doubtful accounts	$	6,960	$	838		$	—	$	(3,451	)	$	4,347	$	6,960	$	838		$	—	$	(3,451	)	$	4,347
Valuation allowance for deferred tax assets		40,202		(8,990	)		—		—			31,212		40,202		(3,567	)		—		—			36,635

Year Ended September 28, 2013
Allowance for doubtful accounts													$	4,347	$	6,717		$	—	$	(4,278	)	$	6,786
Valuation allowance for deferred tax assets														36,635		9,771			—		—			46,406

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (do not check if a smaller reporting company)

Smaller reporting company