Edgar Filing: SUBURBAN PROPANE PARTNERS LP

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (do not check if a smaller reporting company)

Smaller reporting company

10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended September 28, 2013

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

Commission File Number: 1-14222

SUBURBAN PROPANE PARTNERS, L.P.

(Exact name of registrant as specified in its charter)


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

240 Route 10 West

Whippany, NJ 07981

(973) 887-5300

(Address, including zip code, and telephone number,

including area code, of registrant’s principal executive offices)

Securities registered pursuant to Section 12(b) of the Act:


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

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x

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

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See 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 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 ($44.50 per unit), was approximately $2,541,902,000.


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

SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES

INDEX TO ANNUAL REPORT ON FORM 10-K


		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		49
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA		52
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE		55
ITEM 9A.	CONTROLS AND PROCEDURES		55
ITEM 9B.	OTHER INFORMATION		56

	PART III

ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND PARTNERSHIP GOVERNANCE		57
ITEM 11.	EXECUTIVE COMPENSATION		63
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS		87
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE		89
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES		90

	PART IV

ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES		91

SIGNATURES			92

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

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

•

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

•

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

•

The cost savings expected from the Partnership’s acquisition of the retail propane operations formerly owned by Inergy, L.P. (the “Inergy Propane Acquisition”) may not be fully realized or realized within the expected time frame;

•

The revenue gained by the Partnership from the Inergy Propane Acquisition may be lower than expected;

•

The costs of integrating the business acquired in the Inergy Propane Acquisition into the Partnership’s existing operations may be greater than expected;

•

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

•

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

•

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

•

The ability of the Partnership to retain customers or acquire new customers;

•

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

•

The ability of management to continue to control expenses;

•

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

•

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

•

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

•

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

•

The Partnership’s ability to make strategic acquisitions and successfully integrate them, including but not limited to Inergy Propane;

•

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

•

The operating, legal and regulatory risks Suburban may face; and

•

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

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

PART I

ITEM 1.

BUSINESS

Development of Business

Suburban Propane Partners, L.P. (the “Partnership”), a publicly traded Delaware limited partnership, is a nationwide marketer and distributor of a diverse array of products meeting the energy needs of our customers. We specialize in the distribution of propane, fuel oil and refined fuels, as well as the marketing of natural gas and electricity in deregulated markets. In support of our core marketing and distribution operations, we install and service a variety of home comfort equipment, particularly in the areas of heating and ventilation. We believe, based on LP/Gas Magazine dated February 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 2012. As of September 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 534.6 million gallons of propane and 53.7 million gallons of fuel oil and refined fuels to retail customers during the year ended September 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 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 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, 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.

With the Inergy Propane Acquisition, we 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 at www.sec.gov.

Upon written request or through an information request link from our website at www.suburbanpropane.com, we will provide, without charge, copies of our Annual Report on Form 10-K for the year ended September 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 Strategy

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

Internal Focus on Driving Operating Efficiencies, Right-Sizing Our Cost Structure and Enhancing Our Customer Mix. We focus internally on improving the efficiency of our existing operations, managing our cost structure and improving our customer mix. Through investments in our technology infrastructure, we continue to seek to improve operating efficiencies and the return on assets employed. We have developed a streamlined operating footprint and management structure to facilitate effective resource planning and decision making. Our internal efforts are particularly focused in the areas of route optimization, forecasting customer usage, inventory control, cash management and customer tracking. 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 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 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.

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

Business Segments

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

Propane

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

•

residential and commercial applications;

•

industrial applications; and

•

agricultural uses.

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

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

Product Distribution and Marketing

We distribute propane through a nationwide retail distribution network consisting of approximately 750 locations in 41 states as of September 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 expanded our operating territories into the midwest region of the United States. As of September 28, 2013, we serviced approximately 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 97% of the propane gallons sold by us in fiscal 2013 were to retail customers: 49% to residential customers, 29% to commercial customers, 6% to industrial customers, 5% to agricultural customers and 11% to other retail users. The balance of approximately 3% of the propane gallons sold by us in fiscal 2013 was for risk management activities and wholesale customers. No single customer accounted for 10% or more of our propane revenues during fiscal 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.

Supply

Our propane supply is purchased from approximately 65 oil companies and natural gas processors at approximately 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 2014. During fiscal 2013, Inergy Services (a subsidiary of Inergy) and Targa Liquids Marketing and Trade (“Targa”) provided approximately 34% and 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 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 Inergy to remain one of our largest propane suppliers in fiscal 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 99% of our total propane purchases were from domestic suppliers in fiscal 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 28, 2013, the majority of our storage capacity in California was leased to third parties.

Competition

According to the 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 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 2011 Sales of Natural Gas Liquids and Liquefied Refinery Gases, as published by the American Petroleum Institute in February 2013, and LP/Gas Magazine dated February 2013, the ten largest retailers, including us, account for approximately 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.

Fuel Oil and Refined Fuels

Product Distribution and Marketing

We market and distribute fuel oil, kerosene, diesel fuel and gasoline to approximately 68,000 residential and commercial customers primarily in the northeast region of the United States. Sales of fuel oil and refined fuels for fiscal 2013 amounted to 53.7 million gallons. Approximately 65% of the fuel oil and refined fuels gallons sold by us in fiscal 2013 were to residential customers, principally for home heating, 11% were to commercial customers, and 2% to other users. Sales of diesel and gasoline accounted for the remaining 22% of total volumes sold in this segment during fiscal 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 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 2013.

Supply

We obtain fuel oil and other refined fuels in pipeline, truckload or tankwagon quantities, and have contracts with certain pipeline and terminal operators for the right to temporarily store fuel oil at 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 50 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 2014.

Competition

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

Natural Gas and Electricity

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

We serve nearly 87,000 natural gas and electricity customers in New York and Pennsylvania. During fiscal 2013, we sold approximately 4.2 million dekatherms of natural gas and 550.6 million kilowatt hours of electricity through the natural gas and electricity segment. Approximately 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.

All Other

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

Seasonality

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

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

Trademarks and Tradenames

We utilize a variety of trademarks and tradenames owned by us, including “Suburban Propane” and “Suburban Cylinder Express.” As part of the Inergy Propane Acquisition, we acquired a number of different tradenames, such as “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” in connection with the distribution of petroleum-based fuel and sales and service of heating and ventilation products. We regard our trademarks, tradenames and other proprietary rights as valuable assets and believe that they have significant value in the marketing of our products and services.

Government Regulation; Environmental and Safety Matters

We are subject to various federal, state and local environmental, health and safety laws and regulations. Generally, these laws impose limitations on the discharge of 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 28, 2013, we had accrued environmental liabilities of $0.7 million representing the total estimated future liability for remediation and 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. We have 1,180 facilities registered with the DHS, of which 1,161 facilities have been determined to be “Not a High Risk Chemical Facility”. Nineteen facilities have been determined by DHS to be High Risk, Tier 4 (lowest level of security risk). Security Vulnerability Assessments for the 19 facilities have been submitted to the DHS and Site Security Plans are being prepared when deemed necessary by the 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.

Employees

As of September 28, 2013, we had 3,933 full time employees, of whom 683 were engaged in general and administrative activities (including fleet maintenance), 39 were engaged in transportation and product supply activities and 3,211 were customer service center employees. As of September 28, 2013, 127 of our employees were represented by 16 different local chapters of labor unions. We believe that our relations with both our union and non-union employees are satisfactory. From time to time, we hire temporary workers to meet peak seasonal demands.

ITEM 1A.

RISK FACTORS

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.

Risks Related to Our Business and Industry

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 4%, 14% and 1% warmer than normal for fiscal 2013, fiscal 2012 and fiscal 2011, respectively, as measured by the number of heating degree days reported by the National Oceanic and Atmospheric Administration (“NOAA”). Furthermore, variations in weather in one or more regions in which we operate can significantly affect the total volume of propane, fuel oil and other refined fuels and natural gas we sell and, consequently, our results of operations. Variations in the weather in the northeast, where we have a greater concentration of 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 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.

Risks Related to the Inergy Propane Acquisition and the Related Transactions

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. Although we have developed, and are implementing, a detailed integration plan, the combination of two large businesses is a complex and costly process. 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. 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 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 are now being serviced by Suburban. Although not yet experienced to any significant degree, possible difficulties that may yet arise from our continuing efforts to combine our two operations could include, among others:

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operating a significantly larger combined company with operations in more geographic areas;

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maintaining employee morale and retaining key employees;

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developing and implementing employment polices to facilitate workforce integration, and, where applicable, labor and union relations;

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preserving important strategic and customer relationships;

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the diversion of management’s attention from ongoing business concerns;

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the integration of multiple information systems;

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regulatory, legal, taxation and other unanticipated issues in integrating operating and financial systems;

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coordinating marketing functions;

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consolidating corporate and administrative infrastructures and eliminating duplicative operations; and

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integrating the cultures of Suburban and Inergy Propane.

In addition, even if we are able to successfully 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.

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. Although integration expenses have been, to date, within the expected range, many of the expenses yet to be incurred are, by their nature, difficult to accurately estimate 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 integration of Inergy Propane could cause disruptions in our business, which could have an adverse effect on both our business and financial results.

In response to the 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 employees may experience uncertainty about their future roles with us until Inergy Propane is fully integrated. This may adversely affect our ability to attract and retain key management, marketing and technical personnel.

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

Our future success 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 because of issues relating to the uncertainty and difficulty of integration, a desire not to remain with us 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.

Risks Inherent in the Ownership of Our Common Units

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

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

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

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

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

•

issuances of debt and equity securities;

•

our ability to control expenses;

•

fluctuations in working capital;

•

capital expenditures; and

•

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

Our 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 28, 2013, our long-term debt borrowings consisted of $496.6 million in aggregate principal amount of 7.5% senior notes due October 1, 2018 (excluding unamortized premium of $28.6 million), $250.0 million in aggregate principal amount of 7.375% senior notes due March 15, 2020 (excluding unamortized discount of $1.4 million), $346.2 million in aggregate principal amount of 7.375% senior notes due August 1, 2021 (excluding unamortized premium of $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 2.0 to 1.0 as of the end of any fiscal 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 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.

Unitholders have limited voting rights.

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.

Unitholders may not have limited liability in some circumstances.

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

•

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

•

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

Unitholders may have liability to repay distributions.

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

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

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

Tax Risks to Unitholders

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, 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 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.

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

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.

ITEM 1B.

UNRESOLVED STAFF COMMENTS

None.

ITEM 2.

PROPERTIES

As of September 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 28, 2013, we had a fleet of 19 transport truck tractors, of which we owned 12, and 23 railroad tank cars, of which we owned none. In addition, as of September 28, 2013 we had 1,466 bobtail and rack trucks, of which we owned 56%, 150 fuel oil tankwagons, of which we owned 71%, and 1,587 other delivery and service vehicles, of which we owned 62%. We lease the vehicles we do not own. As of September 28, 2013, we also owned 981,468 customer propane storage tanks with typical capacities of 100 to 500 gallons, 83,890 customer propane storage tanks with typical capacities of over 500 gallons and 304,390 portable propane cylinders with typical capacities of five to ten gallons.

ITEM 3.

LEGAL PROCEEDINGS

Litigation

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. During the fourth quarter of fiscal 2012, we entered into an agreement to settle 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. 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 in May 2013, and we completed distribution of the settlement 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.

ITEM 4.

MINE SAFETY DISCLOSURES

None.

PART II

ITEM 5.

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

(a) Our Common Units, representing limited partner interests in the Partnership, are listed and traded on the New York Stock Exchange (“NYSE”) under the symbol SPH. As of November 25, 2013, there were 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
	Common Unit Price Range				Declared per
	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
Second Quarter		48.25		40.25		0.8525
Third Quarter		44.52		34.58		0.8525
Fourth Quarter		45.61		36.75		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.

(b) Not applicable.

ITEM 6.

SELECTED FINANCIAL DATA

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


	Year Ended
	September			September			September			September			September
	28, 2013			29, 2012 (a)			24, 2011			25, 2010			26, 2009
Statement of Operations Data
Revenues	$	1,703,606		$	1,063,458		$	1,190,552		$	1,136,694		$	1,143,154
Costs and expenses		1,526,630			1,003,885			1,047,324			980,508			932,539
Acquisition-related costs (b)		—			17,916			—			—			—
Pension settlement charge (c)		—			—			—			2,818			—
Operating income		176,976			41,657			143,228			153,368			210,615
Interest expense, net		95,427			38,633			27,378			27,397			38,267
Loss on debt extinguishment (d)		2,144			2,249			—			9,473			4,624
Provision for income taxes		607			137			884			1,182			2,486
Net income		78,798			638			114,966			115,316			165,238
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	$	3.50		$	3.41		$	3.41		$	3.35		$	3.26

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

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

Other Data
Depreciation and amortization	$	130,384		$	47,034		$	35,628		$	30,834		$	30,343
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		534,621			283,841			298,902			317,906			343,894
Fuel oil and refined fuels		53,710			28,491			37,241			43,196			57,381

(a)

Fiscal 2012 includes 53 weeks of operations compared to 52 weeks in each of fiscal 2013, 2011, 2010, and 2009. In addition, on August 1, 2012, we acquired Inergy Propane. The results of operations of Inergy Propane have been included in the consolidated results from the Acquisition Date through September 29, 2012 and all of fiscal 2013, and the assets and liabilities of Inergy Propane have been included in the consolidated balance sheet since September 29, 2012. Refer to Note 3—Acquisition of Inergy Propane included within the Notes to the Consolidated Financial Statements section elsewhere in this Annual Report.

(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.

(c)	We incurred non-cash pension settlement charges of $2.8 million during fiscal 2010 to accelerate the recognition of actuarial losses in our defined benefit pension plan as a result of the level of lump sum retirement benefit payments made.

(d)

On August 2, 2013, we repurchased pursuant to optional redemption $133.4 million of our 7.375% Senior Notes due August 1, 2021 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 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. During fiscal 2012 we amended the Credit Agreement (the “Amended Credit Agreement”) to increase the five-year $250.0 million revolving credit facility (the “Revolving Credit Facility”) to $400.0 million, of which, $100.0 million was outstanding as of September 28, 2013, and also 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 for the write-off of previously incurred debt origination costs associated with lenders who did not participate, or whose lending capacity decreased, in the amended facility. On August 1, 2012, we amended the Amended Credit Agreement to provide for a $250.0 million senior secured 364-day incremental term loan facility (the “364-Day Facility”). On August 1, 2012, in connection with the Inergy Propane Acquisition, we drew $225.0 million on the 364-Day Facility and on August 14, 2012, using the proceeds of our secondary offering of common units, we repaid the $225.0 million term loan facility, and wrote off $1.7 million of unamortized commitment fees associated with the 364-Day Facility. During fiscal 2010 we completed the issuance of $250.0 million of 7.375% senior notes maturing in March 2020 to replace the previously existing 6.875% senior notes that were set to mature in December 2013. In connection with the refinancing, we recognized a loss on debt extinguishment of $9.5 million in the second quarter of fiscal 2010, consisting of $7.2 million for the repurchase premium and related fees, as well as the write-off of $2.2 million in unamortized debt origination costs and unamortized discount. During fiscal 2009, we purchased $175.0 million aggregate principal amount of the 6.875% senior notes through a cash tender offer. In connection with the tender offer, we recognized a loss on the extinguishment of debt of $4.6 million in the fourth quarter of fiscal 2009, consisting of $2.8 million for the tender premium and related fees, as well as the write-off of $1.8 million in unamortized debt origination costs and unamortized discount.

(e)

Computations of basic earnings per Common Unit were performed by dividing net income by the weighted average number of outstanding Common Units, and restricted units granted under our 2000 and 2009 Restricted Unit Plans (which we collectively refer to as the “Restricted Unit Plans” or the “RUP”) to retirement-eligible grantees. Computations of diluted earnings per Common Unit were performed by dividing net income by the weighted average number of outstanding Common Units and unvested restricted units granted under our Restricted Unit Plans. On May 17, 2013, we sold 2.7 million Common Units in a public offering. On May 22, 2013, following the underwriters’ exercise of their over-allotment option, we sold an additional 0.4 million Common Units. On August 1, 2012, in connection with the Inergy Propane Acquisition, we issued 14.2 million Common Units, and on August 14, 2012, we sold 7.2 million Common Units in a secondary offering. Those Common Units have been included in basic and diluted earnings per common unit from the respective dates of issuance.

(f)

EBITDA represents net income before deducting interest expense, income taxes, depreciation and amortization. Adjusted EBITDA represents EBITDA excluding the unrealized net gain or loss from mark-to-market activity for derivative instruments 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 accounting principles generally accepted in the United States of America (“US GAAP”) and should not be considered as an alternative to net income or net cash provided by operating activities determined in accordance with US GAAP. Because EBITDA and Adjusted EBITDA as determined by us excludes some, but not all, items that affect net income, they may not be comparable to EBITDA and Adjusted EBITDA or similarly titled measures used by other companies.

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


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

EBITDA		305,216			86,442			178,856			174,729			236,334
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			—			—			—
Loss on asset disposal		—			2,078			—			—			—
Severance charges		—			—			2,000			—			—
Pension settlement charge		—			—			—			2,818			—

Adjusted EBITDA		329,253			108,536			179,425			192,420			239,245
Add (subtract):
Provision for income taxes—current		(607	)		(137	)		(884	)		(1,182	)		(1,101	)
Interest expense, net		(95,427	)		(38,633	)		(27,378	)		(27,397	)		(38,267	)
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	)		—			—
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		(3,543	)		(727	)		(2,772	)		38			(650	)
Changes in working capital and other assets and liabilities		2,635			55,642			(18,958	)		(6,687	)		43,215

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

(g)

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

ITEM 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Executive Overview

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

Product Costs and Supply

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

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

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

Seasonality

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

Weather

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

Hedging and Risk Management Activities

We engage in hedging and risk management activities to reduce the effect of price volatility on our product costs and to ensure the availability of product during periods of short supply. We enter into propane forward, 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 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.

Critical Accounting Policies and Estimates

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

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

Allowances for Doubtful Accounts. We maintain allowances for doubtful accounts for estimated losses resulting from the inability of our customers to make required payments. We estimate our allowances for doubtful accounts using a specific reserve for known or anticipated uncollectible accounts, as well as an estimated reserve for potential future uncollectible accounts taking into consideration our historical write-offs. If the financial condition of one or more of our customers were to deteriorate resulting in an impairment in their ability to make payments, additional allowances could be required. As a result of our large customer base, which is comprised of 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 a self-insurance provision up to the estimated amount of the probable claim utilizing actuarially determined loss development factors applied to actual claims data. Our self-insurance provisions are susceptible to change to the extent that actual claims development differs from historical claims development. We maintain insurance coverage wherein our net exposure for insured claims is limited to the insurance deductible, claims above which are paid by our insurance carriers. For the portion of our estimated self-insurance liability that exceeds our deductibles, we record an asset related to the amount of the liability expected to be paid by the insurance companies. Historically, we have not experienced significant variability in our actuarial estimates for claims incurred but not reported. Accrued insurance provisions for reported claims are reviewed at least quarterly, and our assessment of whether a loss is probable and/or reasonably estimable is updated as necessary. Due to the inherently uncertain nature of, in particular, product liability claims, the ultimate loss may differ materially from our estimates. However, because of the nature of our insurance arrangements, those material variations historically have not, nor are they expected in the future to have, a material impact on our results of operations or financial position.

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

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.

Results of Operations and Financial Condition

For comparative purposes, fiscal 2013 included 52 weeks of operations compared to 53 weeks in fiscal 2012. In addition, the variances in year-over-year results were primarily attributable to the inclusion of Inergy Propane, acquired on August 1, 2012, as well as improvements in the operating performance in our legacy operations. Net income for fiscal 2013 amounted to $78.8 million, or $1.35 per Common Unit, compared to $0.6 million, or $0.02 per Common Unit, in fiscal 2012. Earnings before interest, taxes, depreciation and amortization (“EBITDA”) for fiscal 2013 amounted to $305.2 million, compared to $86.4 million for fiscal 2012.

Net income and EBITDA for fiscal 2013 included: (i) $10.6 million in expenses related to the ongoing integration of Inergy Propane; (ii) $7.0 million in 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 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; (iii) a $2.1 million non-cash charge from a loss on disposal of an asset in our natural gas and electricity 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 2013, compared to Adjusted EBITDA of $108.5 million in fiscal 2012.

Retail propane gallons sold for fiscal 2013 increased 250.8 million gallons, or 88.4%, to 534.6 million gallons from 283.8 million gallons in fiscal 2012. Sales of fuel oil and other refined fuels also increased 88.4%, to 53.7 million gallons from 28.5 million gallons in the prior year. The increase in volumes sold was primarily attributable to the inclusion of the Inergy Propane operations for a full year, as well as increases in our legacy operations resulting from average temperatures that were closer to normal compared to the prior year’s near record warm 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.

During fiscal 2013, we made notable progress in our integration efforts and 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 2013:

•

Key regional management positions were put in place to oversee the combined operations prior to the start of the 2012/2013 heating season;

•

Regular and ongoing communication was established with the entire Inergy Propane customer base, as well as the combined employee base in order to manage change;

•

We defined our local operating footprint and identified management teams across the entire platform;

•

Substantial progress was made on our retail system conversions that support our new operating footprint; and

•

We reduced our overall leverage by $157.3 million through a combination of net proceeds from a successful issuance of Common Units, as well as cash on hand.

Despite the increased size of our business and 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 of cash. Additionally, as previously reported, we took steps to further strengthen our balance sheet by redeeming $157.3 million of debt in fiscal 2013 with a combination of proceeds from a successful equity offering and cash on hand.

As we look ahead to fiscal 2014, our anticipated cash requirements include: (i) maintenance and growth capital expenditures of approximately $30.0 million; (ii) approximately $88.1 million of interest and income tax payments; and (iii) approximately $211.1 million of distributions to Unitholders, assuming distributions at the current annualized rate of $3.50 per Common Unit. Based on our current cash position, availability under the Revolving Credit Facility (unused borrowing capacity of $253.3 million at September 28, 2013) and expected cash flow from operating activities, we expect to have sufficient funds to meet our current and future obligations.

Fiscal Year 2013 Compared to Fiscal Year 2012

Revenues


(Dollars in thousands)
	Fiscal		Fiscal				Percent
	2013		2012		Increase		Increase
Revenues
Propane	$	1,357,102	$	843,648	$	513,454		60.9	%
Fuel oil and refined fuels		208,957		114,288		94,669		82.8	%
Natural gas and electricity		79,432		67,419		12,013		17.8	%
All other		58,115		38,103		20,012		52.5	%

Total revenues	$	1,703,606	$	1,063,458	$	640,148		60.2	%

Total revenues increased $640.1 million, or 60.2%, to $1,703.6 million for fiscal 2013 compared to $1,063.5 million for the prior year due to higher volumes sold, offset to an extent by lower average propane, fuel oil and refined fuels and natural gas selling prices. The increase in sales volumes was primarily due to the addition of the Inergy Propane business, as well as increases in our legacy operations resulting from colder average temperatures. As discussed above, average temperatures (as measured in heating degree days) across all of our service territories for fiscal 2013 were 4% warmer than normal, compared to 14% warmer than normal for the prior year.

Revenues from the distribution of propane and related activities of $1,357.1 million for fiscal 2013 increased $513.5 million, or 60.9%, compared to $843.6 million for the prior year, primarily due to higher volumes sold, partially offset by lower average selling prices associated with lower product costs. Retail propane gallons sold in fiscal 2013 increased 250.8 million gallons, or 88.4%, to 534.6 million gallons from 283.8 million gallons in the prior year, primarily as a result of the addition of Inergy Propane, as well as increases in our legacy operations resulting from colder average temperatures. Higher retail propane volumes sold resulted in an increase in revenues of $679.8 million for fiscal 2013 compared to the prior year. Average propane selling prices for fiscal 2013 decreased 11.5% compared to the prior year due to lower wholesale product costs, resulting in a $166.9 million decrease in revenues year-over-year. Included within the propane segment are revenues from risk management activities and other propane activities of $74.7 million for fiscal 2013, which increased $0.6 million compared to the prior year as higher volumes from other propane activities were substantially offset by lower volumes from wholesale and risk management activities.

Revenues from the distribution of fuel oil and refined fuels of $209.0 million for fiscal 2013 increased $94.7 million, or 82.8%, from $114.3 million for the prior year, primarily due to higher volumes sold, partially offset by lower average selling prices. Fuel oil and refined fuels gallons sold in fiscal 2013 increased 25.2 million gallons, or 88.4%, to 53.7 million gallons from 28.5 million gallons in the prior year, primarily as a result of the addition of Inergy Propane, as well as increases in our legacy operations resulting from colder average temperatures. Higher fuel oil and refined fuels volumes sold resulted in an increase in revenues of $100.5 million for fiscal 2013 compared to the prior year. Average selling prices in our fuel oil and refined fuels segment in fiscal 2013 decreased 2.6% compared to the prior year, resulting in a $5.8 million decrease in revenues year-over-year.

Revenues in our natural gas and electricity segment increased $12.0 million, or 17.8%, to $79.4 million in fiscal 2013 compared to $67.4 million in the prior year as a result of higher natural gas volumes sold, and higher electricity average selling prices. The increase in volumes sold was primarily attributable to the more favorable weather pattern in fiscal 2013, compared to the unseasonably warm weather in the prior year.

Cost of Products Sold


(Dollars in thousands)
	Fiscal			Fiscal					Percent
	2013			2012			Increase		Increase
Cost of products sold
Propane	$	612,240		$	448,120		$	164,120		36.6	%
Fuel oil and refined fuels		172,022			91,239			80,783		88.5	%
Natural gas and electricity		55,995			46,915			9,080		19.4	%
All other		21,648			12,785			8,863		69.3	%

Total cost of products sold	$	861,905		$	599,059		$	262,846		43.9	%

As a percent of total revenues		50.6	%		56.3	%

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 2013 were 19.2% lower than the prior year, and fuel oil prices were essentially flat year-over-year. Total cost of products sold increased $262.8 million, or 43.9%, to $861.9 million in fiscal 2013 compared to $599.1 million in the prior year due to higher volumes sold, partially offset by lower average propane product costs. The net change in the fair value of derivative instruments during the period resulted in unrealized (non-cash) losses of $4.3 million and unrealized (non-cash) gains of $4.6 million reported in cost of products sold in fiscal 2013 and 2012, respectively, resulting in an increase of $8.9 million in cost of products sold in fiscal 2013 compared to the prior year, all of which was reported in the propane segment.

Cost of products sold associated with the distribution of propane and related activities of $612.2 million for fiscal 2013 increased $164.1 million, or 36.6%, compared to the prior year. Higher retail propane volumes sold resulted in an increase of $368.4 million in cost of products sold during fiscal 2013 compared to the prior year. The impact of the increase in volumes sold was partially offset by lower average propane costs, which resulted in a $190.0 million decrease in cost of products sold year-over-year. Cost of products sold from other propane activities decreased $23.2 million in fiscal 2013 compared to the prior year, primarily due to lower sales from wholesale and risk management activities.

Cost of products sold associated with our fuel oil and refined fuels segment of $172.0 million for fiscal 2013 increased $80.8 million, or 88.5%, compared to the prior year primarily due to higher fuel oil and refined fuels volumes sold.

Cost of products sold in our natural gas and electricity segment of $56.0 million for fiscal 2013 increased $9.1 million, or 19.4%, compared to the prior year, primarily due to higher natural gas volumes sold, and higher electricity product costs.

Total cost of products sold as a percent of total revenues decreased 5.7 percentage points to 50.6% in fiscal 2013 from 56.3% in the prior year, primarily due to the decline in propane wholesale product costs outpacing the decline in propane average selling prices. In addition, colder average temperatures and the inclusion of Inergy Propane operations resulted in a higher concentration of residential volumes sold in fiscal 2013 compared to the prior year, which had a favorable impact on overall gross margins.

Operating Expenses


(Dollars in thousands)
	Fiscal			Fiscal					Percent
	2013			2012			Increase		Increase
Operating expenses	$	469,496		$	298,772		$	170,724		57.1	%
As a percent of total revenues		27.6	%		28.1	%

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

Operating expenses of $469.5 million for fiscal 2013 increased $170.7 million, or 57.1%, compared to $298.8 million in the prior year, primarily due to the addition of Inergy Propane, offset to an extent by lower payroll and benefit related expenses in our legacy operations resulting from operating efficiencies. In addition, operating expenses for fiscal 2013 included a $7.0 million charge related to our voluntary partial withdrawal from a multi-employer pension plan and full withdrawal from four multi-employer pension plans, and a charge of $4.6 million primarily for severance costs, both charges were associated with the integration of the Inergy Propane operations. These charges were excluded from our calculation of Adjusted EBITDA below.

As a result of the progress on our efforts to integrate the operations of Inergy Propane, including the initial process of blending geographic territories and systems, which commenced at the beginning of the third quarter of fiscal 2013, we have realized certain synergies in the combined operating expenses of Inergy Propane and our legacy operations.

General and Administrative Expenses


(Dollars in thousands)
	Fiscal			Fiscal					Percent
	2013			2012			Increase		Increase
General and administrative expenses	$	64,845		$	59,020		$	5,825		9.9	%
As a percent of total revenues		3.8	%		5.5	%

All costs of our back office support functions, including compensation and benefits for executives and other support functions, as well as other costs and expenses to maintain finance and accounting, treasury, legal, human 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 $64.8 million for fiscal 2013 increased $5.8 million compared to $59.0 million for the prior year, primarily due to higher variable compensation associated with higher earnings, offset to an extent by a $2.2 million gain on the sale of an asset in fiscal 2013. In addition, general and administrative expenses for fiscal 2013 included $6.0 million of professional services and other expenses associated with the integration of the Inergy Propane operations. 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. These items were excluded from our calculation of Adjusted EBITDA below.

Acquisition-related Costs

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.

Depreciation and Amortization


(Dollars in thousands)
	Fiscal			Fiscal					Percent
	2013			2012			Increase		Increase
Depreciation and amortization	$	130,384		$	47,034		$	83,350		177.2	%
As a percent of total revenues		7.7	%		4.4	%

Depreciation and amortization expense of $130.4 million in fiscal 2013 increased $83.4 million, primarily as a result of the acquired tangible and identifiable intangible assets of Inergy Propane.

Interest Expense, net


(Dollars in thousands)
	Fiscal			Fiscal					Percent
	2013			2012			Increase		Increase
Interest expense, net	$	95,427		$	38,633		$	56,794		147.0	%
As a percent of total revenues		5.6	%		3.6	%

Net interest expense of $95.4 million for fiscal 2013 increased $56.8 million compared to $38.6 million in the prior year, primarily due to the issuance of $496.6 million in aggregate principal amount of 7.5% senior notes due October 1, 2018 and $503.4 million in aggregate principal amount of 7.375% senior notes due August 1, 2021 in connection with the Inergy Propane Acquisition on August 1, 2012. See Liquidity and Capital Resources below for additional discussion.

Loss on Debt Extinguishment

On August 2, 2013, we repurchased, pursuant to an optional redemption, $133.4 million of our 7.375% senior notes due August 1, 2021 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 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.

During fiscal 2012, 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 (defined below) 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 and other financing activities.

Net Income and Adjusted EBITDA

Net income for fiscal 2013 amounted to $78.8 million, or $1.35 per Common Unit, compared to $0.6 million, or $0.02 per Common Unit, in fiscal 2012. Earnings before interest, taxes, depreciation and amortization (“EBITDA”) for fiscal 2013 amounted to $305.2 million, compared to $86.4 million for fiscal 2012.

Net income and EBITDA for fiscal 2013 included: (i) $10.6 million in expenses related to the ongoing integration of Inergy Propane; (ii) $7.0 million in 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 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; (iii) a $2.1 million non-cash charge from a loss on disposal of an asset in our natural gas and electricity 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 amounted to $329.3 million for fiscal 2013, compared to Adjusted EBITDA of $108.5 million in fiscal 2012.

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:


(Dollars in thousands)	Year Ended
	September 28,			September 29,
	2013			2012
Net income	$	78,798		$	638
Add:
Provision for income taxes		607			137
Interest expense, net		95,427			38,633
Depreciation and amortization		130,384			47,034

EBITDA		305,216			86,442
Unrealized (non-cash) losses (gains) on changes in fair value of derivatives		4,318			(4,649	)
Integration-related costs		10,575			—
Multi-employer pension plan withdrawal charge		7,000			—
Loss on debt extinguishment		2,144			2,249
Acquisition-related costs		—			17,916
Loss on legal settlement		—			4,500
Loss on asset disposal		—			2,078

Adjusted EBITDA		329,253			108,536
Add (subtract):
Provision for income taxes		(607	)		(137	)
Interest expense, net		(95,427	)		(38,633	)
Unrealized (non-cash) (losses) gains on changes in fair value of derivatives		(4,318	)		4,649
Integration-related costs		(10,575	)		—
Multi-employer pension plan withdrawal charge		(7,000	)		—
Acquisition-related costs		—			(17,916	)
Loss on legal settlement		—			(4,500	)
Compensation cost recognized under Restricted Unit Plans		3,888			4,059
Gain on disposal of property, plant and equipment, net		(3,543	)		(727	)
Changes in working capital and other assets and liabilities		2,635			55,642

Net cash provided by operating activities	$	214,306		$	110,973

Fiscal Year 2012 Compared to Fiscal Year 2011

Revenues


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

Total revenues	$	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.

Cost of Products Sold


(Dollars in thousands)										Percent
	Fiscal			Fiscal			Increase/			Increase/
	2012			2011			(Decrease)			(Decrease)
Cost of products sold
Propane	$	448,120		$	506,481		$	(58,361	)		(11.5	%)
Fuel oil and refined fuels		91,239			100,908			(9,669	)		(9.6	%)
Natural gas and electricity		46,915			61,495			(14,580	)		(23.7	%)
All other		12,785			9,835			2,950			30.0	%

Total cost of products sold	$	599,059		$	678,719		$	(79,660	)		(11.7	%)

As a percent of total revenues		56.3	%		57.0	%

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.

Operating Expenses


(Dollars in thousands)
	Fiscal			Fiscal					Percent
	2012			2011			Increase		Increase
Operating expenses	$	298,772		$	281,329		$	17,443		6.2	%
As a percent of total revenues		28.1	%		23.6	%

Operating expenses of $298.7 million for fiscal 2012 increased $17.4 million, or 6.2%, compared to $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.

General and Administrative Expenses


(Dollars in thousands)
	Fiscal			Fiscal					Percent
	2012			2011			Increase		Increase
General and administrative expenses	$	59,020		$	51,648		$	7,372		14.3	%
As a percent of total revenues		5.5	%		4.3	%

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.

Acquisition-related Costs

Depreciation and Amortization


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

Depreciation and amortization expense of $47.0 million in fiscal 2012 increased $11.4 million, or 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.

Interest Expense, net


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

Loss on Debt Extinguishment

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.

Net Income and Adjusted EBITDA

We reported net income of $0.6 million, or $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.

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


(Dollars in thousands)	Year Ended
	September 29,			September 24,
	2012			2011
Net income	$	638		$	114,966
Add:
Provision for income taxes		137			884
Interest expense, net		38,633			27,378
Depreciation and amortization		47,034			35,628

EBITDA		86,442			178,856
Unrealized (non-cash) (gains) losses on changes in fair value of derivatives		(4,649	)		(1,431	)
Acquisition-related costs		17,916			—
Loss on legal settlement		4,500			—
Loss on debt extinguishment		2,249			—
Loss on asset disposal		2,078			—
Severance charges		—			2,000

Adjusted EBITDA		108,536			179,425
Add (subtract):
Provision for income taxes		(137	)		(884	)
Interest expense, net		(38,633	)		(27,378	)
Unrealized (non-cash) gains (losses) on changes in fair value of derivatives		4,649			1,431
Severance charges		—			(2,000	)
Acquisition-related costs		(17,916	)		—
Loss on legal settlement		(4,500	)		—
Compensation cost recognized under Restricted Unit Plans		4,059			3,922
Gain on disposal of property, plant and equipment, net		(727	)		(2,772	)
Changes in working capital and other assets and liabilities		55,642			(18,958	)

Net cash provided by operating activities	$	110,973		$	132,786

Liquidity and Capital Resources

Analysis of Cash Flows

Operating Activities. Net cash provided by operating activities for fiscal 2013 amounted to $214.3 million, an increase of $103.3 million compared to the prior year. The increase was primarily attributable to an increase in earnings, after adjusting for non-cash items in both 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 the realization of working capital 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 result of a purchase price adjustment attributable to the working capital of Inergy Propane. Net cash used in investing activities of $239.8 million for fiscal 2012 consisted of 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 financing activities for fiscal 2013 of $226.7 million reflects the quarterly distribution to Common Unitholders at a rate of $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 from the issuance of 3,105,000 of our Common Units in May 2013. The net proceeds from the equity offering, along with cash on hand, were used to redeem $157.3 million of our 2021 Senior Notes in August 2013.

Net cash provided by financing activities for fiscal 2012 of $113.5 million 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.

See Summary of Long-Term Debt Obligations and Revolving Credit Lines below for additional discussion.

Equity Offering

On May 17, 2013, we sold 2,700,000 Common Units in a public offering at a price of $48.16 per Common Unit realizing proceeds of $124.7 million, net of underwriting commissions and other offering expenses. On May 22, 2013, following the underwriters’ exercise of their over-allotment option, we sold an additional 405,000 Common Units at $48.16 per Common Unit, generating additional proceeds of $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.

Summary of Long-Term Debt Obligations and Revolving Credit Lines

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

Senior Notes

2018 Senior Notes and 2021 Senior Notes

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 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.


Year	Percentage
2014		103.750	%
2015		101.875	%
2016 and thereafter		100.000	%

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 December 19, 2012, we completed an offer to exchange our 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, interest rate, maturity and redemption rights) to the Old Notes for which they were exchanged, except that the Exchange Notes generally will not be subject to transfer restrictions.

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 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.

2020 Senior Notes

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 and 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.


Year	Percentage
2015		103.688	%
2016		102.459	%
2017		101.229	%
2018 and thereafter		100.000	%

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 or more gradations) within 90 days of the consummation of the change of control.

Credit Agreement

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 28, 2013 and September 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. As of January 5, 2012, 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. Also, at such time, 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 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 third quarter of fiscal 2014, such minimum ratio will be 2.5 to 1.0. The maximum consolidated leverage ratio decreases over time, 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 second quarter of fiscal 2013, such maximum ratio will be 4.75 to 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 28, 2013 the minimum consolidated interest coverage ratio and maximum consolidated leverage ratio was 2.25 to 1.0 and 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 plus ¹⁄₂ of 1%, the agent bank’s prime rate, or LIBOR plus 1%, plus in each case the applicable margin. The applicable margin is dependent upon the Partnership’s ratio of 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, the Operating Partnership entered into an interest rate swap agreement with a notional amount of $100.0 million, an effective date of March 31, 2010 and termination date of June 25, 2013. Under the interest rate swap agreement, the Operating Partnership 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 paid to the Operating Partnership a floating rate, namely LIBOR, on the same notional principal amount. The interest rate swap 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 and a 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 28, 2013, our Operating Partnership had standby letters of credit issued under the Revolving Credit Facility in the aggregate amount of $46.7 million which expire periodically through April 3, 2014. Therefore, as of September 28, 2013 we had available borrowing capacity of $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 and 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, 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 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 28, 2013 and September 29, 2012 include debt origination costs with a net carrying amount of $21.3 million and $28.1 million, respectively.

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

Partnership Distributions

We are required to make distributions in an amount equal to all of our Available Cash, as defined in the Partnership Agreement, as amended, no more than 45 days after the end of each fiscal quarter to holders of record on the applicable record dates. Available Cash, as defined in the Partnership Agreement, generally means all cash on hand at the end of the respective fiscal quarter less the amount of cash reserves established by the Board of Supervisors in its reasonable discretion for future cash requirements. These reserves are retained for the proper conduct of our business, the payment of debt principal and interest and for distributions during the next four quarters. The Board of Supervisors reviews the level of Available Cash on a quarterly basis based upon information provided by management.

On October 24, 2013, we announced that our Board of Supervisors had declared a quarterly distribution of $0.8750 per Common Unit for the three months ended September 28, 2013. This quarterly distribution rate equates to an annualized rate of $3.50 per Common Unit, which represents a growth rate of 2.6% when compared to the annualized rate of $3.41 per Common Unit as of the end of fiscal year 2012. The distribution was paid on November 12, 2013 to Common Unitholders of record as of November 5, 2013.

Pension Plan Assets and Obligations

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 or 2011. As of September 28, 2013 and September 29, 2012 the plan’s projected benefit obligation exceeded the fair value of plan assets by $27.9 million and $32.0 million, respectively. As a result, the net liability recognized in the consolidated financial statements for the defined benefit pension plan decreased by $4.1 million during fiscal 2013, which was primarily attributable to a decrease in the present value of the benefit obligation due to a general increase in market interest rates, partially offset by a decline in the value of plan assets as a result of investment losses during fiscal 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, 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 28, 2013 and September 29, 2012, we used a discount rate of 4.375% and 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.

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

Long-Term Debt Obligations and Operating Lease Obligations

Contractual Obligations

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


											Fiscal
(Dollars in thousands)	Fiscal		Fiscal		Fiscal		Fiscal		Fiscal		2019 and
	2014		2015		2016		2017		2018		thereafter
Long-term debt obligations	$	—	$	—	$	—	$	100,000	$	496,557	$	596,180
Interest payments		86,356		86,356		86,356		82,568		81,210		122,869
Operating lease obligations (a)		27,238		20,488		12,770		7,894		5,208		5,947
Self-insurance obligations (b)		14,552		11,910		9,021		5,300		3,284		14,085
Other contractual obligations (c)		5,087		5,702		5,032		2,465		2,204		17,450

Total	$	133,233	$	124,456	$	113,179	$	198,227	$	588,463	$	756,531

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

(b)

The timing of when payments are due for our self-insurance obligations is based on estimates that may differ from when actual payments are made. In addition, the payments do not reflect amounts to be recovered from our insurance providers, which amount to $4.3 million, $3.5 million, $2.8 million, $1.5 million, $1.0 million and $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.

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

Operating Leases

We lease certain property, plant and equipment for various periods under noncancelable operating leases, including 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 and $18.9 million for fiscal 2013, 2012 and 2011, respectively. Future minimum rental commitments under noncancelable operating lease agreements as of September 28, 2013 are presented in the table above.

Off-Balance Sheet Arrangements

Guarantees

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

Recently Issued Accounting Pronouncements.

In 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 ASU to establish the effective date for the requirement to present components of reclassifications out of accumulated other comprehensive income either parenthetically on the face of the financial statements or in the notes to the financial statements (“ASU 2013-02”). The guidance is effective prospectively for annual periods beginning after December 15, 2012, and interim periods within those annual periods, which will be the first quarter of our 2014 fiscal year. The adoption of ASU 2013-02 will not change the items that must be reported in other comprehensive income.

ITEM 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

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

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

Under our hedging and risk management strategies, we enter into a combination of exchange-traded futures and 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 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.

Credit Risk

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.

Interest Rate Risk

A portion of our borrowings bear interest at prevailing interest rates based upon, at the Operating Partnership’s option, LIBOR, plus an applicable margin or the base rate, defined as the higher of the Federal Funds Rate plus ¹⁄₂ of 1% or the agent bank’s prime rate, or LIBOR plus 1%, plus the applicable margin. The applicable margin is dependent on the level of the Partnership’s total consolidated leverage ratio (the 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 28, 2013, the fair value of the interest rate swaps was a net liability of $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.

Derivative Instruments and Hedging Activities

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.

Sensitivity Analysis

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

The fair value of open positions as of September 28, 2013.

The market prices for the underlying commodities used to determine A. above were adjusted adversely by a hypothetical 10% change and compared to the fair value amounts in A. above to project the potential negative impact on earnings that would be recognized for the respective scenario.

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

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Our Consolidated Financial Statements and the Report of Independent Registered Public Accounting Firm thereon listed on the accompanying Index to Financial Statements 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.

Selected Quarterly Financial Data

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


	First			Second			Third			Fourth			Total
	Quarter			Quarter			Quarter			Quarter (a)			Year
Fiscal 2013
Revenues	$	490,703		$	678,426		$	290,805		$	243,672		$	1,703,606
Cost of products sold		245,100			346,999			148,176			121,630			861,905
Operating income (loss)		82,308			153,977			(20,654	)		(38,655	)		176,976
Loss on debt extinguishment (b)		—			—			—			2,144			2,144
Net income (loss)		57,620			129,484			(45,187	)		(63,119	)		78,798
Net income (loss) per common unit—basic (c)		1.05			2.29			(0.77	)		(1.05	)		1.35
Net income (loss) per common unit—diluted (c)		1.04			2.28			(0.77	)		(1.05	)		1.34
Cash provided by (used in)
Operating activities		61,537			72,426			66,505			13,838			214,306
Investing activities		1,847			(4,999	)		(6,532	)		(4,979	)		(14,663	)
Financing activities		(48,605	)		(49,965	)		93,459			(221,617	)		(226,728	)
EBITDA (d)	$	112,835		$	185,293		$	10,850		$	(3,762	)	$	305,216
Adjusted EBITDA (d)	$	117,473		$	190,668		$	19,171		$	1,941		$	329,253
Retail gallons sold
Propane		153,933			210,314			92,109			78,265			534,621
Fuel oil and refined fuels		15,885			23,223			8,331			6,271			53,710

Fiscal 2012
Revenues	$	299,886		$	357,626		$	179,601		$	226,345		$	1,063,458
Cost of products sold		183,574			208,401			88,776			118,308			599,059
Operating income (loss)		30,290			56,125			(2,744	)		(42,014	)		41,657
Loss on debt extinguishment (b)		—			507			—			1,742			2,249
Net income (loss)		23,232			49,573			(9,323	)		(62,844	)		638
Net income (loss) per common unit—basic (c)		0.65			1.39			(0.26	)		(1.32	)		0.02
Net income (loss) per common unit—diluted (c)		0.65			1.38			(0.26	)		(1.32	)		0.02
Cash provided by (used in)
Operating activities		(25,323	)		42,371			56,202			37,723			110,973
Investing activities		(4,714	)		(2,775	)		(4,528	)		(227,741	)		(239,758	)
Financing activities		(30,226	)		(32,684	)		(32,072	)		208,531			113,549
EBITDA (d)	$	38,075		$	63,267		$	5,728		$	(20,628	)	$	86,442
Adjusted EBITDA (d)	$	39,123		$	65,852		$	3,460		$	101		$	108,536
Retail gallons sold
Propane		74,279			89,941			49,014			70,607			283,841
Fuel oil and refined fuels		7,695			10,565			4,314			5,917			28,491

(a)

The fourth quarter of fiscal 2012 includes 14 weeks of operations compared to 13 weeks in the fourth quarter for fiscal 2013. In addition, on August 1, 2012, we acquired Inergy Propane. The results of operations of Inergy Propane have been included in the consolidated results from the Acquisition Date through September 29, 2012 and all of fiscal 2013. Refer to Note 3—Acquisition of Inergy Propane included within the Notes to the Consolidated Financial Statements section elsewhere in this Annual Report.

(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.

(c)

Basic net income (loss) per Common Unit is computed by dividing net income (loss) by the weighted average number of outstanding Common Units, and restricted units granted under the Restricted Unit Plans to retirement-eligible grantees. Computations of diluted net income per Common Unit are performed by dividing net income by the weighted average number of outstanding Common Units and unvested restricted units granted under our Restricted Unit Plans. Diluted loss per Common Unit for the periods where a net loss was reported does not include unvested restricted units granted under our Restricted Unit Plans as their effect would be anti-dilutive. On May 17, 2013, we sold 2.7 million Common Units in a public offering. On May 22, 2013, following the underwriters’ exercise of their over-allotment option, we sold an additional 0.4 million Common Units. On August 1, 2012, in connection with the Inergy Propane Acquisition, we issued 14.2 million Common Units, and on August 14, 2012, we sold 7.2 million Common Units in a secondary offering. Those Common Units have been included in basic and diluted earnings per common unit from the respective dates of issuance.

(d)

EBITDA represents net income before deducting interest expense, income taxes, depreciation and amortization. Adjusted EBITDA represents EBITDA excluding the unrealized net gain or loss from mark-to-market activity for derivative instruments 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 (used in) operating activities (amounts in thousands):


	First			Second			Third			Fourth			Total
	Quarter			Quarter			Quarter			Quarter			Year
Fiscal 2013
Net income (loss)	$	57,620		$	129,484		$	(45,187	)	$	(63,119	)	$	78,798
Add:
Provision for income taxes		132			150			148			177			607
Interest expense, net		24,556			24,343			24,385			22,143			95,427
Depreciation and amortization		30,527			31,316			31,504			37,037			130,384

EBITDA		112,835			185,293			10,850			(3,762	)		305,216
Unrealized (non-cash) losses (gains) on changes in fair value of derivatives		3,614			2,646			73			(2,015	)		4,318
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		—			—			—			2,144			2,144

Adjusted EBITDA		117,473			190,668			19,171			1,941			329,253
Add (subtract):
Provision for income taxes		(132	)		(150	)		(148	)		(177	)		(607	)
Interest expense, net		(24,556	)		(24,343	)		(24,385	)		(22,143	)		(95,427	)
Unrealized (non-cash) (losses) gains on changes in fair value of derivatives		(3,614	)		(2,646	)		(73	)		2,015			(4,318	)
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		1,240			1,173			840			635			3,888
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		(25,583	)		(89,224	)		79,649			37,793			2,635

Net cash provided by operating activities	$	61,537		$	72,426		$	66,505		$	13,838		$	214,306


	First			Second			Third			Fourth			Total
	Quarter			Quarter			Quarter			Quarter			Year
Fiscal 2012
Net income (loss)	$	23,232		$	49,573		$	(9,323	)	$	(62,844	)	$	638
Add:
Provision for (benefit from) income taxes		220			(380	)		100			197			137
Interest expense, net		6,838			6,425			6,479			18,891			38,633
Depreciation and amortization		7,785			7,649			8,472			23,128			47,034

EBITDA		38,075			63,267			5,728			(20,628	)		86,442
Unrealized (non-cash) losses (gains) on changes in fair value of derivatives		1,048			—			(8,218	)		2,521			(4,649	)
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		39,123			65,852			3,460			101			108,536
Add (subtract):
(Provision for) benefit from income taxes		(220	)		380			(100	)		(197	)		(137	)
Interest expense, net		(6,838	)		(6,425	)		(6,479	)		(18,891	)		(38,633	)
Unrealized (non-cash) (losses) gains on changes in fair value of derivatives		(1,048	)		—			8,218			(2,521	)		4,649
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		(57,511	)		(18,404	)		56,177			75,380			55,642

Net cash (used in) provided by operating activities	$	(25,323	)	$	42,371		$	56,202		$	37,723		$	110,973

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A.

CONTROLS AND PROCEDURES

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

Before filing this Annual Report, the Partnership completed an evaluation under the supervision and with the participation of the Partnership’s management, including the Partnership’s principal executive officer and principal financial officer, of the effectiveness of the design and operation of the Partnership’s disclosure controls and procedures as of September 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 28, 2013.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING. There have not been any changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) during the quarter ended September 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 REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING. Management of the Partnership is responsible for establishing and maintaining adequate internal control over financial reporting. The Partnership’s internal control over financial reporting is designed to provide reasonable assurance as to the reliability of the Partnership’s financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

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

The Partnership’s management has assessed the effectiveness of the Partnership’s internal control over financial reporting as of September 28, 2013. In making this assessment, the Partnership used the criteria established by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in “Internal Control-Integrated Framework.” These criteria are in the areas of control environment, risk assessment, control activities, information and communication, and monitoring. The Partnership’s assessment included documenting, evaluating and testing the design and operating effectiveness of its internal control over financial reporting.

Based on the Partnership’s assessment, as described above, management has concluded that, as of September 28, 2013, the Partnership’s internal control over financial reporting was effective.

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

ITEM 9B.

OTHER INFORMATION

None.

PART III

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS AND PARTNERSHIP GOVERNANCE

Partnership Management

Our Partnership Agreement provides that all management powers over our business and affairs are exclusively vested in our Board of Supervisors and, subject to the direction of the Board of Supervisors, our officers. No Unitholder has any management power over our business and affairs or actual or apparent authority to enter into contracts on behalf of or otherwise to bind us. 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 beginning of our 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 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 (i) integrity of the Partnership’s financial statements and internal control over financial reporting; (ii) the Partnership’s compliance with applicable laws, regulations and its code of conduct; (iii) independence and qualifications of the independent registered public accounting firm; (iv) performance of the internal audit function and the independent registered public accounting firm; and (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

Board of Supervisors and Executive Officers of the Partnership

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


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

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 8 years and Chief Executive Officer for the past 4 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.

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 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 training inner city individuals to become computer and software technicians), The Berkshire Choral Festival and Landmark Volunteers and also serves on the Board of Directors of The Clark Foundation and The Robert Sterling Clark Foundation and 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.

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, 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 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 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) Beneficial Ownership Reporting Compliance

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

Codes of Ethics and of Business Conduct

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

Corporate Governance Guidelines

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

Audit Committee Charter

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

Compensation Committee Charter

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

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.

NYSE Annual CEO Certification

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

ITEM 11.

EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

This Compensation Discussion and Analysis explains our executive compensation philosophy, policies and practices with respect to the following executive officers of 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: 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.

Executive Compensation Philosophy and Components

The objectives of our executive compensation program are as follows:

•

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

•

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

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

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

•

Base salary;

•

Cash incentives paid under a performance-based annual bonus plan;

•

Long-Term Incentive Plan awards; and

•

Awards of restricted units under the Restricted Unit Plans.

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

•

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

•

Providing a long-term incentive plan that encourages our executive officers to implement activities and practices conducive to sustainable, profitable growth; and

•

Providing our executive officers with restricted units in order to encourage the retention of the participating executive officers, while simultaneously encouraging behaviors conducive to the long-term appreciation of our Common Units.

Establishing Executive Compensation

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 at www.suburbanpropane.com, the Committee ensures that the compensation packages provided to our executive officers are designed in accordance with our compensation philosophy. The Committee reviews and approves the compensation packages of our managing directors, assistant vice presidents, vice presidents, 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 2013 was derived from the Mercer Human Resource Consulting, Inc. (“Mercer”) Benchmark Database containing information obtained from surveys of over 2,543 organizations and approximately 209 positions which may or may not include similarly-sized national 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 $4.2 billion per year.

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 13, 2012, the Committee created fiscal 2013 compensation packages for our executive officers that emphasized the performance-based components of compensation.

The 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 overwhelmingly approved the advisory “Say-on-Pay” resolution required by Section 14A of the Exchange Act. As a result, the Committee determined that no major revisions of its practices are required; however, the Committee has, and will continue to, periodically evaluate its compensation practices for possible improvement.

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 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.

Among other duties, the Committee has overall responsibility for:

•

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

•

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

•

Evaluating and approving our annual cash bonus plan, long-term incentive plan, and grants under our Restricted Unit Plans, as well as all other executive compensation policies and programs;

•

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

•

Engaging consultants, when appropriate, to provide independent, third-party advice on executive officer-related compensation.

Allocation Among Components

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


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

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

Internal Pay Equity

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

Base Salary

Base salaries for the named executive officers and all of our other executive officers, are reviewed and approved annually by the Committee. In order to determine base salary increases, the Committee’s practice is to compare each executive officer’s base salary with the corresponding mean salary provided in the Mercer database. The Committee usually determines base salary adjustments, which may be higher or lower than the comparative data, following an assessment of our overall results as well as each executive officer’s position, performance and scope of responsibility, while at the same time considering each executive officer’s previous total cash compensation opportunities. In accordance with this process and the philosophy described above, and 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
Michael J. Dunn, Jr.	$	495,000	$	475,000
Michael A. Stivala	$	300,000	$	275,000
Steven C. Boyd	$	290,000	$	270,000
Mark Wienberg	$	280,000	$	250,000
Douglas T. Brinkworth	$	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 Bonus Plan

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 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; acquisition-related costs; integration-related costs; multiemployer pension plan withdrawal charges; pension settlement charges; and losses on debt extinguishment. Under the annual cash bonus plan, our executive officers have the opportunity to earn between 60% and 120% of their target cash bonuses, depending upon Suburban’s EBITDA performance in the fiscal 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, no such discretionary adjustments were made to the annual cash bonuses earned by our executives.

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


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%

(1)	Budgeted cash bonus plan EBITDA for fiscal 2013.

The fiscal 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 2013 are summarized as follows:


Name	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%	$	495,000	$	297,000
Michael A. Stivala	80%	$	240,000	$	144,000
Steven C. Boyd	80%	$	232,000	$	139,200
Mark Wienberg	80%	$	224,000	$	134,400
Douglas T. Brinkworth	80%	$	216,000	$	129,600

For purposes of establishing the cash bonus targets for fiscal 2013, the Committee reviewed and approved our fiscal 2013 budgeted cash bonus plan EBITDA at its November 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 have the opportunity to earn between 60% and 120% of their target cash bonuses. Over the past three years, our actual cash bonus plan EBITDA was such that each of our executive officers earned 60%, 0% and 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 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 2013 and 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.

Long-Term Incentive Plans

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 unit plan that has been designed to motivate our executive officers to focus on our long-term financial goals. 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.

The LTIP is designed to:

•

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

•

Provide long-term compensation opportunities consistent with market practice;

•

Reward long-term value creation; and

•

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

LTIP History

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.

Calculation of LTIP Units

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):


	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

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).


	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

Performance Metrics

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 members of the peer groups selected by the Committee for the fiscal 2013, fiscal 2012 and fiscal 2011 awards consist entirely of publicly-traded partnerships. The Committee decided upon these peer groups because all publicly-traded partnerships have similar tax attributes and can, as a result, distribute more cash than similarly-sized corporations generating similar revenues. At its November 13, 2012 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 tables list, in alphabetical order, the names and ticker symbols of the peer group used to measure our performance during the three-year measurement periods for the fiscal 2013, 2012 and fiscal 2011 awards under the LTIP:

Fiscal 2012 and Fiscal 2011 Awards 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, 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

(1)

Copano Energy, LLC was acquired by Kinder Morgan Energy Partners, L.P. on May 1, 2013. For purposes of measuring relative TRU for the fiscal 2011 award, we used Copano’s final closing price, prior to the consummation of the acquisition by Kinder Morgan, in place of an end-of-year twenty-day average. For purposes of measuring relative TRU for the fiscal 2013 and fiscal 2012 awards, as a result of this event, we have reduced the peer groups of those awards by one member.

(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 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.

Cash Payments

For awards granted under the 2003 and 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:

•

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

•

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

•

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

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:

•

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

•

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

•

The sum of the products of the two preceding calculations multiplied by the applicable percentage corresponding to the distribution coverage ratio illustrated in the following table:


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	%

Retirement Provision

A retirement-eligible participant’s outstanding awards under the LTIP 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 2013, fiscal 2012 and fiscal 2011 are reported in the column titled “Unit Awards” in the Summary Compensation Table below.

Restricted Unit Plans

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 2013, there remained 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 meets all three of the following conditions on his or her retirement date:

•

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

•

The grantee is age 55 or older; and

•

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

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

•

To attract skilled and capable candidates to fill vacant positions;

•

To retain the services of an employee;

•

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

•

To reward outstanding performance.

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

•

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

•

The total cash compensation opportunity provided to the executive officer or key employee for whom the award is being considered;

•

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

•

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

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

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

During fiscal 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:


Grant Name	Date	Quantity
Michael A. Stivala	November 15, 2012		8,432
Steven C. Boyd	November 15, 2012		8,432
Mark Wienberg	November 15, 2012		8,432
Douglas T. Brinkworth	November 15, 2012		8,432

In determining the fiscal 2013 awards for Mr. Stivala, Mr. Boyd, Mr. Wienberg and Mr. Brinkworth, the Committee relied upon information provided by the Mercer database to conclude that these awards were necessary to remediate shortfalls perceived by the Committee in the cash compensation 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, 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.

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


Grant Name	Date	Quantity
Michael A. Stivala	November 15, 2013		5,302
Steven C. Boyd	November 15, 2013		5,302
Mark Wienberg	November 15, 2013		5,302
Douglas T. Brinkworth	November 15, 2013		5,302

No award was granted to our Chief Executive Officer at this meeting 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.

Equity Holding Policy

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

Suburban’s equity holding requirements are as follows:


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

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

Incentive Compensation Recoupment 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 at www.suburbanpropane.com under the “Investors” tab.

Pension Plan

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

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

Deferred Compensation

All employees, including the named executive officers, who satisfy certain service requirements, are entitled to participate in our IRC Section 401(k) Plan, 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 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 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 $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:


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

(1)	For purposes of the 401(k) plan, the definition of the term “budgeted EBITDA” is identical to that of “budgeted cash bonus plan EBITDA” discussed under the heading titled “Annual Cash Bonus Plan” above.

Actual cash bonus plan EBITDA, when applied to the 401(k) plan, was such that we provided participants in the 401(k) plan with a matching contribution equal to 25% of their calendar year 2013 contributions that did not exceed 6% of their total base pay, up to a maximum annual compensation limit of $255,000. The matching contributions made on behalf of our named executive officers for 2013 are reported in the column titled “All Other Compensation” in the Summary Compensation Table below.

Other Benefits

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

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

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

Perquisites

Perquisites represent a minor component of our executive officers’ compensation. Each of the named executive officers is eligible for tax preparation services, a company-provided vehicle, and an annual physical. The following table summarizes both the value and the utilization of these perquisites by the named executive officers in fiscal 2013.


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

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

Impact of Accounting and Tax Treatments of Executive Compensation

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

Although it is Suburban’s practice to comply with the statutory and regulatory provisions of IRC Section 409A, the Suburban Propane, L.P. Severance Protection Plan for Key Employees, which we refer to as the “Severance Plan,” provides that if any payment under the Severance Plan subjects a participant to the 20% 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.

Letter Agreement of Mr. Dunn

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

•

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

•

If on or after the last day of fiscal 2012, Mr. Dunn retires or leaves as a result of an agreed-upon succession plan, he will receive the following if he timely provides us with a release of all claims he might have against us at the time of his departure:

•

A payment equal to two years of base salary paid over a two year period.

•

Continuation of medical and dental benefits at no premium cost to him until attainment of age 65 (Mr. Dunn was 64 at the conclusion of fiscal 2013).

•

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

We also agreed that if there was 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 would not be deemed to have retired or terminated his employment if he simply relinquished the title and responsibilities of President but 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.

Severance Benefits

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

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

Change of Control

Our executive officers and other key employees have built 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 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. 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. Under the provisions of the LTIP document, an amount equal to the 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 cumulative, per-Common Unit distribution from the beginning of an unvested award’s three-year measurement period through the date on which a change of control occurred would become payable to the participants.

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

•

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

•

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

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

Report of the Compensation Committee

The Compensation Committee has reviewed and discussed with management this Compensation Discussion and Analysis. Based on its review and discussions with management, the Committee recommended to the Board of Supervisors that this Compensation Discussion and Analysis be included in this Annual Report on Form 10-K for fiscal 2013.

The Compensation Committee:

John Hoyt Stookey, Chairman

Lawrence C. Caldwell

Matthew J. Chanin

John D. Collins

Harold R. Logan, Jr.

Dudley C. Mecum

Jane Swift

ADDITIONAL INFORMATION REGARDING EXECUTIVE COMPENSATION

Summary Compensation Table

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:


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 ($)
(a)	(b)		(c )		(d)		(e)		(g)		(h)		(i)		(j)
Michael J. Dunn, Jr. President and Chief Executive Officer		2013	$	495,000		—	$	369,124	$	297,000		—	$	54,619	$	1,215,743
		2012	$	475,000		—	$	521,058		—	$	22,308	$	49,280	$	1,067,646
		2011	$	475,000		—	$	729,076	$	285,000	$	3,764	$	49,530	$	1,542,370

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

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

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

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

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

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 and 2011, as well as the value at the grant date of awards made in fiscal years 2013, 2012, and 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
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
LTIP		260,158		120,480		118,303		109,546		107,319

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

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

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

(3)	The amounts reported in this column represent each named executive officer’s annual cash bonus earned in accordance with the performance measures discussed under the subheading “Annual Cash Bonus Plan” in the “Compensation Discussion and Analysis.”

(4)

Nothing is reported in this column because there was a decline in value of the participating named executive officers’ Cash Balance Plan holdings during fiscal 2013. The declines in pension values for fiscal 2013 were as follows: ($24,140), ($28,591), and ($14,743) for Messrs. Dunn, Boyd, and Brinkworth, respectively. Neither Mr. Stivala nor Mr. Wienberg participates in the Cash Balance Plan.

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


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
Type of Compensation	Mr. Dunn		Mr. Stivala		Mr. Boyd		Mr. Wienberg		Mr. Brinkworth
401(k) Match	$	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
Value of Partnership Provided Vehicle		17,047		15,480		7,743		11,676		10,677
Tax Preparation Services		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
Insurance Premiums		19,333		16,577		17,370		16,678		16,619

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


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.

Grants of Plan Based Awards Table for Fiscal 2013

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


							Estimated Future Payments Under Non-Equity Incentive Plan Awards				Estimated Future Payments Under Equity Incentive Plan Awards
Name	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)
Michael J. Dunn, Jr.	RUP ⁽¹⁾
	Bonus ⁽²⁾	30 Sep 12					$	495,000	$	594,000
	LTIP ⁽³⁾	30 Sep 12				6,559					$	369,124	$	461,405
Michael A. Stivala	RUP ⁽¹⁾	15 Nov 12		13 Nov 12												8,432	$	197,351
	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⁾	15 Nov 12		13 Nov 12												8,432	$	197,351
	Bonus ⁽²⁾	30 Sep 12					$	232,000	$	278,400
	LTIP ⁽³⁾	30 Sep 12				3,074					$	172,997	$	216,246
Mark Wienberg	RUP ⁽¹⁾	15 Nov 12		13 Nov 12												8,432	$	197,351
	Bonus ⁽²⁾	30 Sep 12					$	224,000	$	268,800
	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
	LTIP ⁽³⁾	30 Sep 12				2,862					$	161,067	$	201,334

(1)

The quantities reported on these lines represent awards granted under the Restricted Unit Plans. RUP awards granted prior to fiscal 2014 vest as follows: 25% of the award on the third anniversary of the grant date; 25% of the award on the fourth anniversary of the grant date; and 50% of the award on the fifth anniversary of the grant date, subject in each case to continued service through each such date. If a recipient has held an unvested award for at least six months; is 55 years or older; and has worked for Suburban for at least ten years, an award held by such participant will vest six months following such participant’s retirement if the participant retires prior to the conclusion of the normal vesting schedule, unless the Committee exercises its authority to alter the applicability of the plan’s retirement provisions in regard to a particular award. On September 28, 2013, Mr. Dunn was the only named executive officer who held RUP awards and, at the same time, satisfied all three retirement eligibility criteria. A discussion of the general terms of the RUP, and the facts and circumstances considered by the Committee in authorizing the fiscal 2013 awards to the named executive officers, is included in the “Compensation Discussion and Analysis” under the subheading “Restricted Unit Plan.”

(2)

Amounts reported on these lines are the targeted and maximum annual cash bonus compensation potential for each named executive officer under the annual cash bonus plan as described in the “Compensation Discussion and Analysis” under the subheading “Annual Cash Bonus Plan.” Actual amounts earned by the named executive officers for fiscal 2013 were equal to 60% of the “Target” amounts reported on this line. Column (c) (“Threshold $”) was omitted because the annual cash bonus plan does not provide for a minimum cash payment. Because these plan awards were granted to, and 60% of the “Target” awards were earned by, our named executive officers during fiscal 2013, 60% of the “Target” amounts reported under column (d) have been reported in the Summary Compensation Table above.

(3)

The LTIP is a phantom unit plan. Payments, if earned, are based on a combination of (1) the fair market value of our Common Units at the end of a three-year measurement period, which, for purposes of the plan, is the average of the closing prices for the twenty business days preceding the conclusion of the three-year measurement period, and (2) cash equal to the distributions that would have inured to the same quantity of outstanding Common Units during the same three-year measurement period. The fiscal 2013 award “Target” and “Maximum” amounts are estimates based upon (1) the fair market value (the average of the closing prices of our Common Units for the twenty business days preceding September 28, 2013) of our Common Units at the end of fiscal 2013, and (2) the estimated distributions over the course of the award’s three-year measurement period. Column (f) (“Threshold”) was omitted because the LTIP does not provide for a minimum cash payment. The “Target” amount represents a hypothetical payment at 100% of target and the “Maximum” amount represents a hypothetical payment at 125% of target. Detailed descriptions of the plan and the calculation of awards are included in the “Compensation Discussion and Analysis” under the subheading “Long-Term Incentive Plan.”

(4)	This column is frequently used when non-equity incentive plan awards are denominated in units; however, in this case, the numbers reported represent the LTIP units each named executive officer was awarded under the LTIP during fiscal 2013.

(5)

The dollar amounts reported in this column represent the aggregate fair value of the RUP awards on the grant date, net of estimated future distributions during the vesting period. The fair value shown may not be indicative of the value realized in the future upon vesting due to the variability in the trading price of our Common Units.

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

Outstanding Equity Awards at Fiscal Year End 2013 Table

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


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⁾
(a)	(g)		(h)		(i)		(j)
Michael J. Dunn, Jr.⁽¹⁾		8,000	$	370,960		11,817	$	664,557
Michael A. Stivala ⁽²⁾		26,484	$	1,228,063		5,615	$	315,779
Steven C. Boyd ⁽³⁾		25,360	$	1,175,943		5,465	$	307,342
Mark Wienberg ⁽⁴⁾		25,682	$	1,190,874		5,182	$	291,430
Douglas T. Brinkworth ⁽⁵⁾		25,682	$	1,190,874		5,031	$	282,937

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

Vesting Date

Dec 1
2014

Dec 1
2015

Dec 1
2016

Quantity of Units

2,000

4,000

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


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

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


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

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


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

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


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

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

(7)	The figures reported in this column represent the figures reported in column (g) multiplied by the average of the highest and the lowest trading prices of our Common Units on September 27, 2013, the last trading day of fiscal 2013.

(8)

The amounts reported in this column represent the quantities of LTIP units that underlie the outstanding and unvested fiscal 2013 and fiscal 2012 awards under the LTIP. Payments, if earned, will be made to participants at the end of a three-year measurement period and will be based upon our total return to Common Unitholders in comparison to the total return provided by a predetermined peer group of eleven other companies, all of which are publicly-traded partnerships, to their unitholders. For more information on the LTIP, refer to the subheading “Long-Term Incentive Plan” in the “Compensation Discussion and Analysis.”

(9)

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


	Mr. Dunn		Mr. Stivala		Mr. Boyd		Mr. Wienberg		Mr. Brinkworth
Fiscal 2013 LTIP Units		6,559		3,180		3,074		2,968		2,862
Value of Fiscal 2013 LTIP Units	$	300,402	$	145,644	$	140,789	$	135,934	$	131,080
Estimated Distributions over Measurement Period	$	68,722	$	33,318	$	32,208	$	31,097	$	29,987

Fiscal 2012 LTIP Units		5,258		2,435		2,391		2,214		2,169
Value of Fiscal 2012 LTIP Units	$	240,816	$	111,523	$	109,508	$	101,401	$	99,340
Estimated Distributions over Measurement Period	$	54,617	$	25,294	$	24,837	$	22.998	$	22,530

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

Equity Vested Table for Fiscal 2013

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


Restricted Unit Plans	Unit Awards
	Number of Common Units		Value Realized
Name	Acquired on Vesting (#)		on Vesting ($) ⁽¹⁾
Michael J. Dunn, Jr.		14,765	$	595,842
Michael A. Stivala		3,618	$	146,004
Steven C. Boyd		3,624	$	146,247
Mark Wienberg		2,080	$	83,938
Douglas T. Brinkworth		3,784	$	152,703

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


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

(2)	The fiscal 2011 award’s three-year measurement period concluded on September 28, 2013.

(3)

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

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

Pension Benefits Table for Fiscal 2013

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 28, 2013:


Name	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	$	247,290	$	—
	LTIP ⁽³⁾	N/A	$	664,557	$	—
	RUP ⁽⁴⁾	N/A	$	370,960	$	—

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

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

Mark Wienberg ⁽²⁾	N/A	N/A	$	—	$	—

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

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

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

(3)

Currently, Mr. Dunn is the only named executive officer who meets the retirement criteria of the LTIP. For such participants, upon retirement, outstanding but unvested awards under the LTIP become fully vested. However, payouts on those awards are deferred until the conclusion of each outstanding award’s three-year measurement period, based on the outcome of the TRU relative to the peer group. The number reported on this line represents a projected payout of Mr. Dunn’s outstanding fiscal 2013 and fiscal 2012 awards under the LTIP. Because the ultimate payout, if any, is predicated on the trading prices of Suburban’s Common Units at the end of the three-year measurement period, as well as where within the peer group our TRU falls, the value reported may not be indicative of the value realized in the future upon vesting due to the variability in the trading price of our Common Units.

(4)

Currently, Mr. Dunn is the only named executive officer who meets the retirement criteria of the RUP. For more information on this and the retirement provisions, refer to the subheading “Restricted Unit Plans” in the “Compensation Discussion and Analysis.” For participants who meet the retirement criteria, upon retirement, outstanding RUP awards vest six months and one day after retirement.

Potential Payments Upon Termination

The following table sets forth certain information containing potential payments to the named executive officers in accordance with the provisions of Mr. Dunn’s letter agreement, the Severance Protection Plan, the RUP and the LTIP for the circumstances listed in the table assuming a September 28, 2013 termination date. For more information on Mr. Dunn’s letter agreement, refer to the subheading “Letter Agreement of 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
Michael J. Dunn, Jr.
Cash Compensation ^{(1) (2) (3) (4)}	$	-0-	$	990,000	$	990,000	$	1,485,000
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⁾		370,960		370,960		370,960		370,960
Medical Benefits ⁽³⁾		N/A		16,414		16,414		N/A

Total	$	370,960	$	1,377,374	$	1,377,374	$	2,974,948


Michael A. Stivala
Cash Compensation ^{(1) (2) (3) (4)}	$	-0-	$	-0-	$	300,000	$	810,000
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⁾		1,228,063		837,071		N/A		1,228,063
Medical Benefits ⁽³⁾		N/A		N/A		17,179		N/A

Total	$	1,228,063	$	837,071	$	317,179	$	2,565,048


Steven C. Boyd
Cash Compensation ^{(1) (2) (3) (4)}	$	-0-	$	-0-	$	290,000	$	783,000
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⁾		1,175,943		784,951		N/A		1,175,943
Medical Benefits ⁽³⁾		N/A		N/A		17,736		N/A

Total	$	1,175,943	$	784,951	$	307,736	$	2,473,416


Mark Wienberg
Cash Compensation ^{(1) (2) (3) (4)}	$	-0-	$	-0-	$	280,000	$	756,000
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⁾		1,190,874		799,883		N/A		1,190,874
Medical Benefits ⁽³⁾		N/A		N/A		17,159		N/A

Total	$	1,190,874	$	799,883	$	297,159	$	2,430,750


Douglas T. Brinkworth