UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended September 24, 2011

27, 2014

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

Commission File Number: 1-14222

SUBURBAN PROPANE PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

Delaware 22-3410353
Delaware

(State or other jurisdiction of

incorporation or organization)

 22-3410353

(I.R.S. Employer

Identification No.)

240 Route 10 West

Whippany, NJ 07981

(973) 887-5300

(Address, including zip code, and telephone number,

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

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

Title of each class
Common Units

 

Name of each exchange on which registered

Common UnitsNew 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.    Yesþx    Noo¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yeso¨    Noþx

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.    Yesþx    Noo¨

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).    Yesþx    Noo¨

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filerþx  Accelerated filero ¨
Non-accelerated filero Smaller reporting companyo¨
(do  (do not check if a smaller reporting company)  Smaller reporting company¨

Indicate by check mark whether registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).    Yes  Yeso¨    Noþx

The aggregate market value as of March 25, 201129, 2014 of the registrant’s Common Units held by non-affiliates of the registrant, based on the reported closing price of such units on the New York Stock Exchange on such date ($55.7340.89 per unit), was approximately $1,972,717,000.

$2,465,914,000.

Documents Incorporated by Reference: None Total number of pages (excluding Exhibits): 123141

 

 


SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES

INDEX TO ANNUAL REPORT ON FORM 10-K

Page
     Page 
ITEM 1.

BUSINESS

   1  
ITEM 1A. 

   10  
ITEM 1B.

UNRESOLVED STAFF COMMENTS

   22  
ITEM 1B. UNRESOLVED STAFF COMMENTS2.

PROPERTIES

   2022  
ITEM 3.

LEGAL PROCEEDINGS

   22  
ITEM 2. PROPERTIES4.

MINE SAFETY DISCLOSURES

   2022  
PART II
ITEM 5. 
21
21
22
   23  
ITEM 6.

SELECTED FINANCIAL DATA

   24  
ITEM 7.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS   2627  
ITEM 7A. 
44

   47  
ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

   50  
ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE   5053  
ITEM 9A.

CONTROLS AND PROCEDURES

   53  
ITEM 9A. CONTROLS AND PROCEDURES9B.

OTHER INFORMATION

   5054  
PART III
ITEM 10. 
51

   5155  
ITEM 11.

EXECUTIVE COMPENSATION

   61  
ITEM 11. EXECUTIVE COMPENSATION12. 56
   7988  
ITEM 13. 

   8190  
ITEM 14. 

   8291  
PART IV
ITEM 15.

EXHIBITS, FINANCIAL STATEMENT SCHEDULES

   92  
PART IVSIGNATURES   93  
83
84
EX-21.1
EX-23.1
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT


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 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 sufficient volumes of, and the costs to the Partnership of acquiring, transporting and storing, propane, fuel oil and other refined fuels;

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 regulationslaws that could adversely affect the tax treatment of the Partnership for federal income tax purposes;

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

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

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

 


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 onLP/Gas Magazinedated February 2011,2014, that we are the fifththird largest retail marketer of propane in the United States, measured by retail gallons sold in the calendar year 2010.2013. As of September 24, 2011,27, 2014, we were serving the energy needs of approximately 750,0001.2 million residential, commercial, industrial and agricultural customers through approximately 300710 locations in 3041 states located primarilywith operations principally concentrated in the east and west coast regions of the United States, including Alaska. We sold approximately 298.9530.7 million gallons of propane and 37.249.1 million gallons of fuel oil and refined fuels to retail customers during the year ended September 24, 2011.27, 2014. Together with our predecessor companies, we have been continuously engaged in the retail propane business since 1928.

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

Subsidiaries

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 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 was 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. (the “Service Company”), which conducts a portion of the Partnership’sour service work and appliance and parts businesses. The Service Company is the sole member of Gas Connection, LLC (d/b/a HomeTown Hearth & Grill), and Suburban Franchising, LLC. HomeTown Hearth & Grill sells and installs natural gas and propane gas grills, fireplaces and related accessories and supplies through two retail stores in the northwest and northeast regions as of September 24, 2011. Suburban Franchising creates and develops propane related franchising business opportunities.

Through an acquisition in fiscal 2004, we transformed our business from a marketer of a single fuel into one that provides multiple energy solutions, with expansion into the marketing and distribution of fuel oil and refined fuels, as well as the marketing of natural gas and electricity.business. Our fuel oil and refined fuels, natural gas and electricity and services businesses are structured as either limited liability companycompanies 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 Corporation,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 CorporationCorp. 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 and the Service Company commenced operations in March 1996 in connection with the Partnership’s initial public offering of Common Units.

1


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

Upon written request or through an information request link from our website atwww.suburbanpropane.com, we will provide, without charge, copies of our Annual Report on Form 10-K for the year ended September 24, 2011,27, 2014, 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. While weoperations. We are active in this area, we are also very patient and deliberate in evaluating acquisition candidates. During fiscal 2011, weConsistent with this strategy, the Inergy Propane Acquisition, completed an acquisitionon August 1, 2012, was a transformative event for Suburban by expanding our geographic reach, doubling the size of a mid-sized propane business in a market where we already have a strong presence. During fiscal 2010 we completed four acquisitions of mid-sized propane businesses; there were no acquisitions completed during fiscal 2009. These acquisitions complemented our existing operations, expanded our customer base and providing us with opportunities to achieve operational synergies by combining operations in overlapping territories and implementing our focusoperating model and systems platform on operational efficiencies, provided synergies through the blending of operations and assets into our existing facilities.

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.

2


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

residential and commercial applications;

residential and commercial applications;
industrial applications; and
agricultural uses.

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 powerover-the-road vehicles, forklifts and stationary engines, to fire furnaces, as a cutting gas and in other process applications. In the agricultural market, propane is primarily used for tobacco curing, crop drying, poultry brooding and weed control.

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

Product Distribution and Marketing

We distribute propane through a nationwide retail distribution network consisting of approximately 300700 locations in 3041 states as of September 24, 2011.27, 2014. Our operations are principally concentrated in the east and west coast regions of the United States, including Alaska. As of September 24, 2011,27, 2014, we serviced approximately 608,0001,027,000 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 proprietary computer technology, based upon each customer’s historical consumption patterns and prevailing weather conditions. Additionally, we offer our customers a budget payment plan whereby the customer’s estimated annual propane purchases and service contracts are paid for in a series of estimated equal monthly payments over a twelve-month period. From our customer service centers, we also sell, install and service equipment to customers who purchase propane from us including heating and cooking appliances hearth products and supplies and, at some locations, propane fuel systems for motor vehicles.

We sell propane primarily to six customer markets: residential, commercial, industrial (including engine fuel), agricultural, other retail users and wholesale. Approximately 91%97% of the propane gallons sold by us in fiscal 20112014 were to retail customers: 45%49% to residential customers, 28%26% to commercial customers, 8%7% to industrial customers, 4%5% to agricultural customers and 15%13% to other retail users. The balance of approximately 9%3% of the propane gallons sold by us in fiscal 20112014 was for risk management activities and wholesale customers. No single customer accounted for 10% or more of our propane revenues during fiscal 2011.

2014.

3


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 6153 oil companies and natural gas processors at approximately 110190 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. However, during the fiscal 2014 heating season, we were adversely affected by supply constraints resulting from industry-wide supply shortages and logistics issues involving propane transportation sourcing and costs. Nevertheless, through relationships with our suppliers and extraordinary efforts by our supply and logistics personnel, we were able to effectively manage the challenging environment in fiscal 2014 without a material disruption in supply. Although we make no assurance regarding the availability of supplies of propane in the future, we currently expect to be able to secure adequate supplies during fiscal 2012.2015. During fiscal 2011,2014, Crestwood Midstream Partners L.P. (“Crestwood”), Targa Liquids Marketing and Trade (“Targa”) and Enterprise Products OperatingPartners L.P. (“Enterprise”) provided approximately 17%19%, 13% and 11%13% of our total propane purchases, respectively. No other single supplier accounted for more than 10% of our propane purchases in fiscal 2014. The availability of our propane supply is dependent on several factors, including the severity of winter weather, the magnitude of competing demands for available supply (e.g., crop drying and exports), the availability of transportation and storage infrastructure and the price and availability of competing fuels, such as natural gas and fuel oil. We believe that if supplies from Crestwood, Targa or Enterprise were interrupted, we would be able to secure adequate propane supplies from other sources without a material disruption of our operations. Nevertheless, the cost of acquiring and transporting such propane might be higher and, at least on a short-term basis, our margins could be affected. Approximately 96%94% of our total propane purchases were from domestic suppliers in fiscal 2011.

2014.

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

We own and operate a large propane storage facility in California. We also operate smaller storage facilities in other locations and have rights to use storage facilities in additional locations. These storage facilities enable us to buy and store large quantities of propane particularly during periods of low demand, which generally occur during the summer months. This practice helps ensure a more secure supply of propane during periods of intense demand or price instability. As of September 24, 2011,27, 2014, the majority of our storage capacity in California was leased to third parties.

Competition

According to the Energy Information Administration’s Short-Term Energy Outlook Model Documentation (November 2009),US Census Bureau’s 2013 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.

4


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. OverHowever, over the last year or so,few years, fewer new housing developments have been started in our service areas as a result of recent economic circumstances.
The increasing availability of natural gas extracted from shale deposits in the United States may accelerate the extension of natural gas pipelines in the future.

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 in20092012 Sales of Natural Gas Liquids and Liquefied Refinery Gases, as published by the American Petroleum Institute in December 2010,2013, andLP/Gas Magazine dated February 2011,2014, the ten largest retailers, including us, account for approximately 39%44% of the total retail sales of propane in the United States. For fiscal years 2009 through 2011, no single marketer had a greater than 10% share of the total retail propane market in the United States. Each of our customer service centers operates in its own competitive environment because retail marketers tend to locate in close proximity to customers in order to lower the cost of providing service. Our typical customer service center has an effective marketing radius of approximately 50 miles, although in certain areas the marketing radius may be extended by one or more satellite offices. Most of our customer service centers compete with five or more marketers or distributors.

Fuel Oil and Refined Fuels

Product Distribution and Marketing

We market and distribute fuel oil, kerosene, diesel fuel and gasoline to approximately 48,00057,000 residential and commercial customers primarily in the northeast region of the United States. Sales of fuel oil and refined fuels for fiscal 20112014 amounted to 37.249.1 million gallons. Approximately 71%66% of the fuel oil and refined fuels gallons sold by us in fiscal 20112014 were to residential customers, principally for home heating, 4%8% were to commercial customers, 1% were to agricultural and 5%7% to other users. Sales of diesel and gasoline accounted for the remaining 19% of total volumes sold in this segment during fiscal 2011.2014. Fuel oil has a more limited use, compared to propane, and is used almost exclusively for space and water heating in residential and commercial buildings. We sell diesel fuel and gasoline to commercial and industrial customers for use primarily to operate motor vehicles.

Approximately 46%41% of our fuel oil customers receive their fuel oil under an automatic delivery system. These deliveries are scheduled through proprietary computer technology, based upon each customer’s historical consumption patterns and prevailing weather conditions. Additionally, we offer our customers a budget payment plan whereby the customer’s estimated annual fuel oil purchases are paid for in a series of estimated equal monthly payments over a twelve-month period. From our customer service centers, we also sell, install and service equipment to customers who purchase fuel oil from us including heating appliances.

Deliveries of fuel oil are usually made to customers by means of tankwagon trucks, which have capacities ranging from 2,500 gallons to 3,000 gallons. Fuel oil is pumped from the tankwagon truck into a stationary storage tank that is located on the customer’s premises, which is owned by the customer. The capacity of customer storage tanks ranges from approximately 275 gallons to approximately 1,000 gallons. No single customer accounted for 10% or more of our fuel oil revenues during fiscal 2011.

2014.

5


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 1314 terminal facilities we do not own. We have arrangements with certain suppliers of fuel oil, which provide open access to fuel oil at specific terminals throughout the northeast. Additionally, a portion of our purchases of fuel oil are made at local wholesale terminal racks. In most cases, the supply contracts do not establish the price of fuel oil in advance; rather, prices are typically established based upon market prices at the time of delivery plus or minus a differential for transportation and volume discounts. We purchase fuel oil from more than 20approximately 25 suppliers at approximately 60 supply points. While fuel oil supply is more susceptible to longer periods of supply constraint than propane, we believe that our supply arrangements will provide us with sufficient supply sources. Although we make no assurance regarding the availability of supplies of fuel oil in the future, we currently expect to be able to secure adequate supplies during fiscal 2012.

2015.

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 87,000over 80,000 natural gas and electricity customers in New York and Pennsylvania. During fiscal 2011,2014, we sold approximately 4.14.3 million dekatherms of natural gas and 613.9476.2 million kilowatt hours of electricity through the natural gas and electricity segment. Approximately 75%83% 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 isare 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.

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All Other

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

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

Seasonality

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

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

Trademarks and Tradenames

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

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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 by the Environmental Protection Agency 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, we identified that 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 24, 2011,27, 2014, we had accrued environmental liabilities of $0.6 million representing the total estimated future liability for remediation and monitoring.

monitoring of all of our properties.

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

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.

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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 some of our facilities, some of which may be material to our operations. We believe that the procedures currently in effect at all of our facilities for the handling, storage, 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 474a number of facilities registered with the DHS, of which 454 facilities have been determined to be “Not a High Risk Chemical Facility”. 20 facilities have been determined by DHS to be High Risk, Tier 4 (lowest level of security risk). Security Vulnerability Assessments for the 20 facilities have been submitted to the DHS and the DHS has reviewed 17 of them, requiring us to submit Site Security Plans for those facilities. Pending DHS review, the remaining 3 facilities may require Site Security Plans within 90 days of DHS notification.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 orderconnection with our ongoing efforts 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.

The EPA’s authority to regulate GHGs was recently upheld by the U.S. Supreme Court.

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

policies on climate change.

The adoption of federal or state climate change legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased capital and operating costs, with resulting impact on product price and demand. We cannot predict whether or in what form cap-and-tradeclimate 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.

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

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

Required transactional margins, capital, recordkeeping, reporting, clearing and settlement as a result of these exceptions currently is somewhat uncertain, pending further definition through rulemaking.

Among the other provisions oflegislation (such as the Dodd-Frank Act thatAct) and related existing and proposed administrative rulemaking may affect derivative transactions are those relating to establishment of capital and margin requirements for certain derivative participants; establishment of business conduct standards, recordkeeping and reporting requirements; and imposition of position limits.
Although the Dodd-Frank Act imposes significant new regulatory requirements with respect to derivatives, the impact of the requirements will not be known definitively until final regulations have been adopted by the CFTC and the SEC. The new legislation and regulations promulgated thereunder could increase theour operational and transactional cost of entering and maintaining derivatives contracts and adversely affect the number and/or creditworthiness of derivatives counterparties available to us.
If we reduce our use of derivatives as a result of legislation and regulations, our results of operations may become more volatile and our cash flow may be less predictable.

Many of the states in which we do business have passed laws prohibiting “unfair or deceptive practices” in transactions between consumers and sellers of products used for residential purposes, which give the Attorney General or other officials of that state the authority to investigate alleged violations of those laws. From time to time, we receive inquiries or requests for additional information under these laws from the offices of Attorneys General or other government officials in connection with the sale of our products to residential customers. Based on information to date, we do not believe that the costs or liabilities associated with such inquiries or requests will result in a material adverse effect on our financial condition or results of operations; however, there can be no assurance that our financial condition or results of operations may not be materially and adversely affected as a result of current or future government investigations or civil litigation derived therefrom.

Employees

As of September 24, 2011,27, 2014, we had 2,3853,796 full time employees, of whom 477708 were engaged in general and administrative activities (including fleet maintenance), 37 were engaged in transportation and product supply activities and 1,8713,051 were customer service center employees. As of September 24, 2011, 4427, 2014, 121 of our employees were represented by 516 different local chapters of labor unions. We believe that our relations with both our union andnon-union employees are satisfactory. From time to time, we hire temporary workers to meet peak seasonal demands.

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.Statements. See “Disclosure Regarding Forward-Looking Statements” aboveabove..

Risks Inherent in ourRelated to Our Business Operations

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.

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Actual weather conditions can vary substantially from year to year, significantly affecting our financial performance. For example, average temperatures in our service territories were 1%, 5%3% colder than normal, and 1%4% and 14% warmer than normal for fiscal 2011,2014, fiscal 20102013 and fiscal 2009,2012, respectively, as measured by the number of heating degree days reported by the National Oceanic and Atmospheric Administration.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 ofour costs to acquire and transport 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, or our inability to obtain adequate supplies of such products from alternative 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 costs to acquire and transport product cost and retail sales price. Propane, fuel oil and other refined fuels and natural gas are commodities, and the availability of those products, and the unit priceprices we need to pay isto acquire and transport those products, are 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. sources, competing demands for the products and infrastructure (including highway, rail, pipeline and refinery) constraints. Our supply of these products from our usual sources may be interrupted due to these and other reasons that are beyond our control, necessitating the transportation of product, if it is available at all, by truck, rail car or other means from other suppliers in other areas, with resulting delay in receipt and delivery to customers and increased expense. As a result, our costs of acquiring and transporting alternative supplies of these products to our facilities 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 and transportation costs of propane, fuel oil and other refined fuels and natural gas, these increases could reduce our profitability. In addition, our inability to obtain sufficient supplies of propane, fuel oil and other refined fuels and natural gas in order for us to fully meet our customer demand for these products on a timely basis could adversely affect our revenues, and consequently our profitability.

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 volatilityincreases in our costs to acquire and transport 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.

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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 currently 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.continue, and, with the increasingly abundant supply of natural gas from domestic sources, perhaps accelerate. Propane and fuel oil compete to a lesser extent with each other due to the cost of converting from one to the other.

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

As a result of the highly competitive nature of the retail propane and fuel oil businesses, our growth within these industries depends on our ability to acquire other retail distributors, open new customer service centers, add new customers and retain existing customers. We can give no assurance that we will be able to acquire other retail distributors, add new customers and retain existing customers.

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

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

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

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

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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 other environmental media, and the 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.

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

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

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

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

The EPA’s authority to regulate GHGs was recently upheld by the U.S. Supreme Court.

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

policies on climate change.

The adoption of federal or state climate change legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased capital and operating costs, with resulting impact on product price and demand. We cannot predict whether or in what form cap-and-tradeclimate 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.

The adoptionOur use of derivativesderivative contracts involves credit and regulatory risk and may expose us to financial loss.

From time to time, we enter into hedging transactions to reduce our business risks arising from fluctuations in commodity prices and interest rates. Hedging transactions expose us to risk of financial loss in some circumstances, including if the other party to the contract defaults on its obligations to us or if there is a change in the expected differential between the price of the underlying commodity or financial metric provided in the hedging agreement and the actual amount received.

Required transactional margins, capital, recordkeeping, reporting, clearing and settlement as a result of legislation by Congress could have an adverse impact on our ability to hedge risks associated with our business.

On July 21, 2010,(such as the Dodd-Frank Act was signed into law. The Dodd-Frank Act regulates derivative transactions, which include certain instruments used inAct) and related existing and proposed administrative rulemaking may increase our risk management activities.
The Dodd-Frank Act requires the CFTC and the SEC to promulgate rules and regulations relating to, among other things, swaps, participants in the derivatives markets, clearing of swaps and reporting of swap transactions. In general, the Dodd-Frank Act subjects swap transactions and participants to greater regulation and supervision by the CFTC and the SEC and will require many swaps to be cleared through a CFTC- or SEC-registered clearing facility and executed on a designated exchange or swap execution facility. There are some exceptions to these requirements for entities that use swaps to hedge or mitigate commercial risk. While we may ultimately be eligible for such exceptions, the scope of these exceptions currently is somewhat uncertain, pending further definition through rulemaking.

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Among the other provisions of the Dodd-Frank Act that may affect derivative transactions are those relating to establishment of capital and margin requirements for certain derivative participants; establishment of business conduct standards, recordkeeping and reporting requirements; and imposition of position limits.
Although the Dodd-Frank Act imposes significant new regulatory requirements with respect to derivatives, the impact of the requirements will not be known definitively until new regulations have been adopted by the CFTC and the SEC. The new legislation and regulations promulgated thereunder could increase the operational and transactional cost of entering and maintaining derivatives contracts and adversely affect the number and/or creditworthiness of derivatives counterparties available to us. If we reduce our use of derivatives as a result of legislation and regulations, our results of operations may become more volatile and our cash flow may be less predictable.

Because we depend on particular management information systems to effectively manage all aspects of our delivery of propane, a failure in our operational systems or cyber security attacks on any of our facilities, or those of third parties, may adversely affect our financial results.

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.

If any of our financial, operational, or other data processing systems fail or have other significant shortcomings, our financial results could be adversely affected. Our financial results also could be adversely affected if an employee or third party causes our operational systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating our operational systems. In addition, dependence upon automated systems may further increase the risk that operational system flaws, employee tampering or manipulation of those systems will result in losses that are difficult to detect or recoup, including damage to our reputation. To the extent customer data is hacked or misappropriated, we could be subject to liability to affected persons.

Risks Related to the Inergy Propane Acquisition and the Related Transactions

We may not be able to successfully complete the integration of 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 need to fully combine and integrate the businesses and operations of Inergy Propane with ours. Although we have developed, and have substantially implemented, a detailed integration plan, the complete integration of two large businesses is a complex and costly process. We continue to devote significant management attention and resources to integrating all of 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 not completed effectively, may preclude realization of the full expected benefits of the transaction.

Our failure to meet the challenges involved in successfully completing the full 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. Although not yet experienced to any significant degree, possible difficulties that may yet arise from our continuing efforts to fully combine our two operations could include, among others:

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

maintaining employee morale and retaining key employees;

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

preserving important strategic and customer relationships; and

fully integrating the cultures of Suburban and Inergy Propane.

In addition, even if we are able to successfully complete the full 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 have 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. 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 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.

Risks Inherent in the Ownership of Our Common Units

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

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

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

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

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

issuances of debt and equity securities;

our ability to control expenses;

fluctuations in working capital;

capital expenditures; and

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

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

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

As of September 24, 2011, we had total outstanding27, 2014, our long-term debt borrowings of $350.0 million, consistingconsisted of $250.0 million in aggregate principal amount of 7.375% senior notes issued by the Partnership and our 100%-owned subsidiary, Suburban Energy Finance Corporation,due March 15, 2020 (excluding unamortized discount of $1.2 million), $346.2 million in aggregate principal amount of 7.375% senior notes due August 1, 2021 (excluding unamortized premium of $22.7 million), $525.0 million in aggregate principal amount of 5.5% senior notes due June 1, 2024, and $100.0 million of borrowings outstanding under the Operating Partnership’sour 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.common units. In addition, we will not be able to make any distributions to holders of our Unitholderscommon units if there is, or after giving effect to such distribution, there would be, an event of default under the indentureindentures governing the senior notes. The amount of distributions that the Partnershipwe may make to its Unitholdersholders of our common units is limited by the senior notes, and the amount of distributions that the Operating Partnership may make to the Partnershipus is limited by theour revolving credit facility.

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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 2.52.0 to 1.0 as of the end of any fiscal quarter;quarter (and commencing with the third quarter of fiscal 2014, such minimum ratio is 2.5 to 1.0); (b) prohibiting our total consolidated leverage ratio, as defined, from being greater than 4.54.75 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 note indenture,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 24, 2011.
27, 2014.

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 distributions on our Common Units may be impacted, depending on the level of revenue generation, which is not assured.

Unitholders have limited voting rights.

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

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

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

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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.

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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. We believeIf 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 under current law, wepartnership will be classifiedtaxable as a partnershipcorporation for U.S. federal income tax purposes.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. The IRS may adopt positions that differ from the positions we take. In addition, current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level federal income taxation. Members of Congress have proposed substantive changes to the current federal income tax laws that would affect certain publicly traded partnerships and legislation that would eliminate partnership tax treatment for certain publicly traded partnerships. Although no legislation is currently pending that would affect our tax treatment as a partnership, weWe are unable to predict whether any suchof these changes, or other proposals, will ultimately be enacted. Any modification to the U.S. tax laws and interpretations thereof may or may not be applied retroactively. If we were treated as a corporation for federal income tax purposes, we would be required to pay tax on our income at corporate tax rates (currently a maximum of U.S. federal rate of 35%) and likely would be required to pay state income tax at varying rates. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our Unitholders would be substantially reduced. Therefore, our treatment as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our Unitholders, likely causing a substantial reduction insuch changes could negatively impact the value of an investment in our Common Units. units.

In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Any such changes could negatively impact our ability to make distributions and also impact the value of an investment in our Common Units.

A successful IRS contest of the 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, to whom we allocate taxable income which could be different in amount than the cash we distribute, a Unitholder is required to pay U.S. federal income taxes and in some cases, state and local income taxes on its allocable share of our income, even if it receives nowithout regard to whether we make cash distributions from us.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 United StatesU.S. federal income tax returns and pay tax on their share of our taxable income. Tax-exempt entitiesorganizations and foreign persons should consult, and should depend on, their own tax advisors before investing in ouranalyzing the U.S. federal, state, local and foreign income tax and other tax consequences of the acquisition, ownership or disposition of Common Units.

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


There are limits onVarious limitations may apply to the ability of a Unitholder’s deductibilityUnitholder to deduct its share of our losses.
In 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. UnusedSuch unused losses may be deducted when the Unitholder disposes of its entire investment in us in a fully taxable transaction with an unrelated party.party, such as a sale by a Unitholder of all of its Common Units in the open market. A Unitholder’s share of ourany 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 unitCommon 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, withwithin 90 days after the close of each calendar year, specific tax information, including a Schedule K-1 that sets forth its allocable share of income, gains, losses and deductions.deductions for our preceding taxable year. In preparing these schedules, we use various accounting and reporting conventions and adopt various depreciation and amortization methods. We cannot guarantee that these conventions will yield a result that conforms to statutory or regulatory requirements or to administrative pronouncements of the IRS. Further, our income tax return may be audited, which could result in an audit of a Unitholder’s income tax return and increased liabilities for taxes because of adjustments resulting from the audit.

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

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

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

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

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

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

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

We will be deemedconsidered to have terminated (and reconstituted)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 Common Unitscapital and profits within a twelve-month period. Were this to occur, itOur 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. This wouldIn 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 Unitholdersmore than twelve months of our taxable income or loss being allocated an increased amountincludable in his taxable income for the year of taxable income.

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 United StatesU.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 United StatesU.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 Unitholder.

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 24 2011,27, 2014, we owned approximately 66%73% of our customer service center and satellite locations and leased the balance of our retail locations from third parties. We own and operate a 22 million gallon refrigerated, aboveground propane storage facility in Elk Grove, California. Additionally, we own our principal executive offices located in Whippany, New Jersey.

The transportation of propane requires specialized equipment. The trucks and railroad tank cars utilized for this purpose carry specialized steel tanks that maintain the propane in a liquefied state. As of September 24 2011,27, 2014, we had a fleet of 612 transport truck tractors, of which we owned two,5, and 23 railroad tank cars, of which we owned none. In addition, as of September 24, 201127, 2014 we had 6681,347 bobtail and rack trucks, of which we owned 33%51%, 88139 fuel oil tankwagons, of which we owned 25%63%, and 8661,360 other delivery and service vehicles, of which we owned 41%54%. We lease the vehicles we do not own. As of September 24, 2011,27, 2014, we also owned 655,003950,257 customer propane storage tanks with typical capacities of 100 to 500 gallons, 139,81369,294 customer propane storage tanks with typical capacities of over 500 gallons and 217,842403,967 portable propane cylinders with typical capacities of five to ten gallons.

 

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ITEM 3.
LEGAL PROCEEDINGS

Litigation

Our operations are subject to all operating hazards and risks normally incidental to handling, storing and delivering combustible liquids such as propane. We have been, and will continue to be, a defendant in various legal proceedings and litigation arising in the ordinary course of business, both as a result of these operating hazards and risks, and as a result of other aspects of our business. In this regard, we currently are a defendant in putative suits in several states. The complaints allege a number of claims, including as to our pricing, fee disclosure and tank ownership, under various consumer statutes, the Uniform Commercial Code, common law and antitrust law. Based on the nature of the allegations under these suits, we believe that the suits are without merit and we are contesting each of these suits vigorously. We are self-insured for general and product, workers’ compensation and automobile liabilities up to predetermined amounts above which third party insurance applies. We believe that the self-insured retentions and coverage we maintain are reasonable and prudent. Although any litigation is inherently uncertain, based on past experience, the information currently available to us, and the amount of our self-insurance reserves for known and unasserted self-insurance claims (which was approximately $52.8 million at September 24, 2011),accrued insurance liabilities, we do not believe that thesecurrently pending or threatened litigation matters, or known claims or known contingent claims, will have a material adverse effect on our future results of operations, financial condition or cash flow, after considering our self-insurance reserves for known and unasserted claims, as well as existing insurance policies in force. For the portion of our estimated self-insurance liability that exceeds our deductibles, we record a corresponding asset related to the amount of the liability covered by insurance (which was approximately $17.5 million at September 24, 2011). With respect to the pending putative suits, other than for legal defense fees and expenses, based on the merits of the allegations, a liability for a loss contingency is not required at this time.

flow.

ITEM 4.
REMOVED AND RESERVED
MINE SAFETY DISCLOSURES

None.

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PART II

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

(a) Our Common Units, representing limited partner interests in the Partnership, are listed and traded on the New York Stock Exchange (“NYSE”) under the symbol SPH. As of November 21, 2011,24, 2014, there were 700670 Unitholders of record (based on the number of record holders and nominees for those Common Units held in street name). The following table presents, for the periods indicated, the high and low sales prices per Common Unit, as reported on the NYSE, and the amount of quarterly cash distributions declared and paid per Common Unit in respect of each quarter.

             
          Cash Distribution 
  Common Unit Price Range  Declared per 
  High  Low  Common Unit 
Fiscal 2011
            
First Quarter $57.24  $51.50  $0.8525 
Second Quarter  58.99   49.30   0.8525 
Third Quarter  57.89   49.90   0.8525 
Fourth Quarter  53.23   40.25   0.8525 
             
Fiscal 2010
            
First Quarter $47.12  $41.10  $0.8350 
Second Quarter  50.00   42.53   0.8400 
Third Quarter  49.46   39.16   0.8450 
Fourth Quarter  55.01   45.85   0.8500 

   Common Unit Price
Range
   Cash Distribution
Declared per
Common Unit
 
   High   Low   

Fiscal 2014

      

First Quarter

  $48.90    $44.21    $0.8750  

Second Quarter

   47.16     39.91     0.8750  

Third Quarter

   48.61     40.94     0.8750  

Fourth Quarter

   46.21     41.13     0.8750  

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  

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.

(c) None.

22


ITEM 6.
SELECTED FINANCIAL DATA

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

                     
  Year Ended 
  September  September  September  September  September 
  24, 2011  25, 2010  26, 2009  27, 2008  29, 2007 
Statement of Operations Data
                    
Revenues $1,190,552  $1,136,694  $1,143,154  $1,574,163  $1,439,563 
Costs and expenses  1,045,324   980,508   932,539   1,424,035   1,270,213 
Severance charges (a)  2,000            1,485 
Pension settlement charge (b)     2,818         3,269 
Operating income  143,228   153,368   210,615   150,128   164,596 
Interest expense, net  27,378   27,397   38,267   37,052   35,596 
Loss on debt extinguishment (c)     9,473   4,624       
Provision for income taxes  884   1,182   2,486   1,903   5,653 
Income from continuing operations  114,966   115,316   165,238   111,173   123,347 
Discontinued operations:                    
Gain on disposal of discontinued operations (d)           43,707   1,887 
Income from discontinued operations              2,053 
Net income  114,966   115,316   165,238   154,880   127,287 
Income from continuing operations per Common Unit — basic  3.24   3.26   4.99   3.39   3.79 
Net income per Common Unit — basic (e)  3.24   3.26   4.99   4.72   3.91 
Net income per Common Unit — diluted (e)  3.22   3.24   4.96   4.70   3.89 
Cash distributions declared per unit $3.41  $3.35  $3.26  $3.09  $2.76 
                     
Balance Sheet Data (f)
                    
Cash and cash equivalents $149,553  $156,908  $163,173  $137,698  $96,586 
Current assets  297,822   296,427   307,556   359,551   295,940 
Total assets  956,459   970,914   978,168   1,036,367   988,947 
Current liabilities, excluding short-term borrowings and current portion of long-term borrowings  151,514   164,514   181,930   226,780   206,633 
Total debt  348,169   347,953   349,415   531,772   548,538 
Total liabilities  598,241   608,258   620,632   818,472   822,670 
Partners’ capital — Common Unitholders $418,134  $419,882  $418,824  $262,050  $208,230 
                     
Statement of Cash Flows Data
                    
Cash provided by (used in)                    
Operating activities $132,786  $155,797  $246,551  $120,517  $145,957 
Investing activities  (19,505)  (30,111)  (16,852)  36,630   (19,689)
Financing activities $(120,636) $(131,951) $(204,224) $(116,035) $(90,253)
                     
Other Data
                    
Depreciation and amortization — continuing operations $35,628  $30,834  $30,343  $28,394  $28,790 
Depreciation and amortization — discontinued operations              452 
EBITDA (g)  178,856   174,729   236,334   222,229   197,778 
Adjusted EBITDA (g)  179,425   192,420   239,245   220,465   210,087 
Capital expenditures — maintenance and growth (h) $22,284  $19,131  $21,837  $21,819  $26,756 
Retail gallons sold                    
Propane  298,902   317,906   343,894   386,222   432,526 
Fuel oil and refined fuels  37,241   43,196   57,381   76,515   104,506 

   Year Ended 
   September 27,
2014
  September 28,
2013
  September 29,
2012 (a)
  September 24,
2011
  September 25,
2010
 

Statement of Operations Data

      

Revenues

  $1,938,257   $1,703,606   $1,063,458   $1,190,552   $1,136,694  

Costs and expenses

   1,748,131    1,526,630    1,003,885    1,047,324    980,508  

Acquisition-related costs (b)

   —      —      17,916    —      —    

Pension settlement charge (c)

   —      —      —      —      2,818  

Operating income

   190,126    176,976    41,657    143,228    153,368  

Interest expense, net

   83,261    95,427    38,633    27,378    27,397  

Loss on debt extinguishment (d)

   11,589    2,144    2,249    —      9,473  

Provision for income taxes

   767    607    137    884    1,182  

Net income

   94,509    78,798    638    114,966    115,316  

Net income per Common Unit—basic (e)

   1.56    1.35    0.02    3.24    3.26  

Net income per Common Unit—diluted (e)

   1.56    1.34    0.02    3.22    3.24  

Cash distributions declared per unit

  $3.50   $3.50   $3.41   $3.41   $3.35  

Balance Sheet Data

      

Cash and cash equivalents

  $92,639   $107,232   $134,317   $149,553   $156,908  

Current assets

   294,865    293,322    337,515    297,822    296,427  

Total assets

   2,609,363    2,727,987    2,883,850    956,459    970,914  

Current liabilities

   222,266    233,894    253,715    151,514    164,514  

Total debt

   1,242,685    1,245,237    1,422,078    348,169    347,953  

Total liabilities

   1,587,910    1,598,861    1,793,351    598,241    608,258  

Partners’ capital—Common Unitholders

  $1,067,358   $1,176,479   $1,151,606   $418,134   $419,882  

Statement of Cash Flows Data

      

Cash provided by (used in)

      

Operating activities

  $225,551   $214,306   $110,973   $132,786   $155,797  

Investing activities

   (16,532  (14,663  (239,758  (19,505  (30,111

Financing activities

  $(223,612 $(226,728 $113,549   $(120,636 $(131,951

Other Data

      

Depreciation and amortization

  $136,399   $130,384   $47,034   $35,628   $30,834  

EBITDA (f)

   314,936    305,216    86,442    178,856    174,729  

Adjusted EBITDA (f)

   338,502    329,253    108,536    179,425    192,420  

Capital expenditures—maintenance and growth (g)

  $30,052   $27,823   $17,476   $22,284   $19,131  

Retail gallons sold

      

Propane

   530,743    534,621    283,841    298,902    317,906  

Fuel oil and refined fuels

   49,071    53,710    28,491    37,241    43,196  

(a)Fiscal 2012 includes 53 weeks of operations compared to 52 weeks in each of fiscal 2014, 2013, 2011 and 2010. 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 fiscal 2014, 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)During fiscal 2011,Due to the Inergy Propane Acquisition on August 1, 2012 we recorded severance chargesacquisition-related costs of $2.0$17.9 million relatedduring fiscal 2012. These costs were primarily attributable to the realignment of our regional operating footprint in response to the persistentinvestment banker, legal, accounting and foreseeable challenges affecting the industry as a whole. During fiscal 2007, we incurred $1.5 million in charges associated with severance for positions eliminated unrelated to any specific plan of restructuring.other consulting fees.

23


(b)(c)We incurred non-cash pension settlement charges of $2.8 million and $3.3 million during fiscal 2010 and 2007, respectively, to accelerate the recognition of actuarial losses in our defined benefit pension plan as a result of the level of lump sum retirement benefit payments made.
(c)(d)On May 27, 2014, we repurchased and satisfied and discharged all of our 2018 Senior Notes with net proceeds from the issuance of the 2024 Senior Notes and cash on hand pursuant to a tender offer and redemption. In connection with this tender offer and redemption, we recognized a loss on the extinguishment of debt of $11.6 million consisting of $31.6 million for the redemption premium and related fees, as well as the write-off of $5.3 million and ($25.3) million in unamortized debt origination costs and unamortized premium, respectively. 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 27, 2014, 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.
(d)Gain on disposal of discontinued operations for fiscal 2008 of $43.7 million reflects the October 2, 2007 sale of our Tirzah, South Carolina underground granite propane storage cavern, and associated 62-mile pipeline, for $53.7 million in net proceeds (the “Tirzah Sale”). Gain on disposal of discontinued operations for fiscal 2007 of $1.9 million reflects the exchange, in a non-cash transaction, of nine non-strategic customer service centers for three customer service centers of another company in Alaska, as well as the sale of three additional customer service centers for net cash proceeds of $1.3 million. The gains on disposal have been accounted for within discontinued operations. The prior period results of operations attributable to the sale of our Tirzah, South Carolina storage cavern and associated pipeline have been reclassified to remove their financial results from continuing operations.
(e)Computations of basic earnings per Common Unit were performed by dividing net income by the weighted average number of outstanding Common Units, and restricted units granted under our restricted unit plans2000 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 restrictedRestricted 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 plans.from the respective dates of issuance.
(f)Other assets and other liabilities on the consolidated balance sheet were increased $654 and $2,835, respectively, with a corresponding decrease of $2,181 to common unitholders as of September 27, 2008 to record an asset and a liability that were not captured in prior years.
(g)EBITDA represents net income before deducting interest expense, income taxes, depreciation and amortization. Adjusted EBITDA represents EBITDA excluding the unrealized net gain or loss from mark-to-market activity for derivative instruments loss on debt extinguishment, pension settlement charge and severance charges.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. In addition, certain of our incentive compensation plans covering executives and other employees utilize Adjusted EBITDA as the performance target. Moreover, our revolving credit agreement requires us to use Adjusted EBITDA in calculating our leverage and interest coverage ratios. EBITDA and Adjusted EBITDA are not recognized terms under accounting principles generally accepted in the United States of America (“US GAAP”) and should not be considered as an alternative to net income or net cash provided by operating activities determined in accordance with US GAAP. Because EBITDA and Adjusted EBITDA as determined by us excludes some, but not all, items that affect net income, they may not be comparable to EBITDA and Adjusted EBITDA or similarly titled measures used by other companies.

24


The following table sets forth (i) our calculations of EBITDA and Adjusted EBITDA and (ii) a reconciliation of EBITDA and Adjusted EBITDA, as so calculated, to our net cash provided by operating activities (amounts in thousands):
                     
  Fiscal  Fiscal  Fiscal  Fiscal  Fiscal 
  2011  2010  2009  2008  2007 
Net income $114,966  $115,316  $165,238  $154,880  $127,287 
Add:                    
Provision for income taxes  884   1,182   2,486   1,903   5,653 
Interest expense, net  27,378   27,397   38,267   37,052   35,596 
Depreciation and amortization                    
Continuing operations  35,628   30,834   30,343   28,394   28,790 
Discontinued operations              452 
                
EBITDA  178,856   174,729   236,334   222,229   197,778 
Unrealized (non-cash) (gains) losses on changes in fair value of derivatives  (1,431)  5,400   (1,713)  (1,764)  7,555 
Severance charges  2,000            1,485 
Loss on debt extinguishment     9,473   4,624       
Pension settlement charge     2,818         3,269 
                
Adjusted EBITDA  179,425   192,420   239,245   220,465   210,087 
Add (subtract):                    
Provision for income taxes — current  (884)  (1,182)  (1,101)  (626)  (1,853)
Interest expense, net  (27,378)  (27,397)  (38,267)  (37,052)  (35,596)
Unrealized (non-cash) gains (losses) on changes in fair value of derivatives  1,431   (5,400)  1,713   1,764   (7,555)
Severance charges  (2,000)           (1,485)
Compensation cost recognized under Restricted Unit Plan  3,922   4,005   2,396   2,156   3,014 
(Gain) loss on disposal of property, plant and equipment, net  (2,772)  38   (650)  (2,252)  (2,782)
Gain on disposal of discontinued operations           (43,707)  (1,887)
Changes in working capital and other assets and liabilities  (18,958)  (6,687)  43,215   (20,231)  (15,986)
                
                     
Net cash provided by operating activities $132,786  $155,797  $246,551  $120,517  $145,957 
                

   Fiscal
2014
  Fiscal
2013
  Fiscal
2012
  Fiscal
2011
  Fiscal
2010
 

Net income

  $94,509   $78,798   $638   $114,966   $115,316  

Add:

      

Provision for income taxes

   767    607    137    884    1,182  

Interest expense, net

   83,261    95,427    38,633    27,378    27,397  

Depreciation and amortization

   136,399    130,384    47,034    35,628    30,834  
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

EBITDA

   314,936    305,216    86,442    178,856    174,729  

Unrealized (non-cash) (gains) losses on changes in fair value of derivatives

   (306  4,318    (4,649  (1,431  5,400  

Integration-related costs

   12,283    10,575    —      —      —    

Loss on debt extinguishment

   11,589    2,144    2,249    —      9,473  

Multi-employer pension plan withdrawal charge

   —      7,000    —      —      —    

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

   338,502    329,253    108,536    179,425    192,420  

Add (subtract):

      

Provision for income taxes

   (767  (607  (137  (884  (1,182

Interest expense, net

   (83,261  (95,427  (38,633  (27,378  (27,397

Unrealized (non-cash) gains (losses) on changes in fair value of derivatives

   306    (4,318  4,649    1,431    (5,400

Integration-related costs

   (12,283  (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

   7,390    3,888    4,059    3,922    4,005  

(Gain) loss on disposal of property, plant and equipment, net

   (521  (3,543  (727  (2,772  38  

Changes in working capital and other assets and liabilities

   (23,815  2,635    55,642    (18,958  (6,687
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Net cash provided by operating activities

  $225,551   $214,306   $110,973   $132,786   $155,797  
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

(h)(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.

25


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.our costs to acquire and transport products. 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

Changes in our costs to acquire and transport products 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 acquisition and transportation cost increases fully or immediately, particularly when productsuch costs increase rapidly. Therefore, average retail sales prices can vary significantly from year to year as productour costs fluctuate with the propane, fuel oil, crude oil and natural gas commodity marketmarkets and infrastructure conditions. In addition, periods of sustained higher commodity and/or transportation 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, approximatelytwo-thirds of our retail propane volume is sold during the six-month peak heating season from October through March. The fuel oil business tends to experience greater seasonality given its more limited use for space heating and approximately three-fourths of our fuel oil volumes are sold between October and March. Consequently, sales and operating profits are concentrated in our first and second fiscal quarters. Cash flows from operations, therefore, are greatest during the second and third fiscal quarters when customers pay for product purchased during the winter heating season. We expect lower operating profits and either net losses or lower net income during the period from April through September (our third and fourth fiscal quarters). To the extent necessary, we will reserve cash from the second and third quarters for distribution to holders of our Common Units in the fourth quarter and the following fiscal year first quarter.

26


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 optionswap agreements with third parties, and use futures and optionoptions 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 optionoptions 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 optionswap contracts are generally settled in cash at the expiration of the contract.contract through a net settlement mechanism. 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, “Summary2—Summary of Significant Accounting Policies included within the Notes to Consolidated Financial Statements section elsewhere in this Annual Report.

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

Allowances for Doubtful Accounts. We maintain allowances for doubtful accounts for estimated losses resulting from the inability of our customers to make required payments. We estimate our allowances for doubtful accounts using a specific reserve for known or anticipated uncollectible accounts, as well as an estimated reserve for potential future uncollectible accounts taking into consideration our historical write-offs. If the financial condition of one or more of our customers were to deteriorate resulting in an impairment in their ability to make payments, additional allowances could be required. As a result of our large customer base, which is comprised of approximately 750,0001.2 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.

27


Pension and Other Postretirement Benefits. We estimate the rate of return on plan assets, the discount rate used to estimate the present value of future benefit obligations and the expected cost of future health care benefits in determining our annual pension and other postretirement benefit costs. While we believe that our assumptions are appropriate, significant differences in our actual experience or significant changes in market conditions may materially affect our pension and other postretirement benefit obligations and our future expense. See “Liquidity and Capital Resources — Pension Plan Assets and Obligations” below for additional disclosure regarding pension benefits.
With other assumptions held constant, an increase or decrease of 100 basis points in the discount rate would have an immaterial impact on net pension and postretirement benefit costs.
See “Liquidity and Capital Resources—Pension Plan Assets and Obligations” below for additional disclosure regarding pension benefits.

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

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

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

Results of Operations and Financial Condition

Net income for fiscal 20112014 amounted to $115.0$94.5 million, or $3.24$1.56 per Common Unit, compared to $115.3$78.8 million, or $3.26$1.35 per Common Unit, in fiscal 2010.2013. Earnings before interest, taxes, depreciation and amortization (“EBITDA”) for fiscal 20112014 amounted to $178.9$314.9 million, compared to $174.7$305.2 million for fiscal 2010.

2013.

Net income and EBITDA for fiscal 2011 included a $2.02014 included: (i) $12.3 million charge for severance costs associated within expenses related to the realignmentongoing integration of the Partnership’s field operations, as well as a non-cash charge of $2.9 million to accelerate depreciation expense on assets taken out of service. By comparison, net incomeInergy Propane and EBITDA for fiscal 2010 included: (i)(ii) a loss on debt extinguishment of $9.5$11.6 million. Net income and EBITDA for fiscal 2013 included: (i) $10.6 million associated with a refinancingin 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 Partnership’s senior notes; (ii) a non-cash pension settlement charge of $2.8 million;Inergy Propane Acquisition; and (iii) a non-cash chargeloss on debt extinguishment of $1.8 million to accelerate depreciation expense$2.1 million. Excluding the effects of these charges, as well as the unrealized (non-cash) mark-to-market adjustments on assets taken out of service.derivative instruments in both years, Adjusted EBITDA (as defined and reconciled below) amounted to $179.4$338.5 million for fiscal 2014, an increase of $9.2 million, or 2.8%, compared to Adjusted EBITDA of $329.3 million in fiscal 2011, compared to $192.4 million in fiscal 2010.

2013.

Retail propane gallons sold for fiscal 20112014 decreased 19.03.9 million gallons, or 6.0%0.7%, to 298.9530.7 million gallons from 317.9534.6 million gallons in fiscal 2010.2013. Sales of fuel oil and other refined fuels for fiscal 2011also decreased 6.08.6%, to 49.1 million gallons or 13.9%, to 37.2 million gallons compared to 43.2from 53.7 million gallons in the prior year. SalesAccording to the NOAA, average temperatures (as measured by heating degree days) across all of our service territories during fiscal 2014 were 3% colder than normal and 7% colder than the prior year period. However, the weather pattern during the winter heating season (October 2013 through March 2014) was characterized by considerably colder than normal temperatures in our service territories in the east and midwest regions, whereas our service territories in the west experienced unseasonably warm temperatures throughout the period. Average temperatures in the western territories during this past winter heating season were 11% warmer than normal and 6% warmer than the comparable period in the prior year, which negatively impacted volumes sold in both segments continued to be negativelythose territories. Additionally, volumes sold during fiscal 2014 were adversely affected by weakness in the economy, coupled withsupply constraints resulting from industry-wide supply shortages and logistics issues, as well as customer conservation attributable to the high commodity price environment relativea significant rise in wholesale propane prices.

During fiscal 2014, we made significant progress, not only in our integration efforts with regards to historical levels. Average posted pricesInergy Propane, but also in executing our strategic financing initiatives. To highlight a few key accomplishments for propanefiscal 2014:

We completed our system conversions and fuel oil were 26.7% and 36.6% higher, respectively, compared to fiscal 2010, as commodity prices continued to rise throughout much of fiscal 2011. From a weather perspective, average temperatures for fiscal 2011 were 1% warmer than normal, compared to 5% warmer than normal in the prior year.physical blending activities associated with the integration of Inergy Propane;

 

We have installed our operating model across the entire platform and have migrated to one common brand;

28


Revenues for fiscal year 2011We successfully refinanced our previous 7.5% Senior Notes due 2018 with new 5.5% Senior Notes due in 2024, which effectively extended maturities on this portion of $1,190.6our debt by six years and reduced our cash interest requirement by more than $8 million increased $53.9 million, or 4.7%, compared to the prior year, primarily due to higher average selling prices attributable to higher base commodity prices, offset to an extent by lower volumes sold. Cost of products sold for fiscal 2011 of $678.7 million increased $80.2 million, or 13.4%, compared to $598.5 millionannually; and

We have successfully transitioned our senior leadership team in the prior year as a result of higher wholesale product costs. Cost of products sold in fiscal 2011 included a $1.4 million unrealized (non-cash) gain attributable to the mark-to-market adjustment for derivative instruments used in risk management activities, compared to a $5.4 million unrealized (non-cash) loss in the prior year; these unrealized gains and losses are excluded from Adjusted EBITDA for both periods.
Combined operating and general and administrative expenses of $331.0 million for fiscal year 2011 were $20.2 million, or 5.8%, lower than the prior year, primarily due to lower variable compensation attributed to lower earnings and continued savings in payroll and benefit related expenses, offset to an extent by higher fuel costs to operate our fleet. Depreciation and amortization expense of $35.6 million increased $4.8 million, or 15.6%, primarily due to the impact of prior year acquisitions, as well as from the increase in accelerated depreciation for assets taken out of service referenced above.
Net interest expense of $27.4 million for fiscal 2011 was flataccordance with the prior year. For the fifth consecutive year, the Partnership funded all working capital requirements with cash on hand without the need to borrow under its working capital facility and ended the year with $149.6 million of cash.Board-approved succession plans.

As we look ahead to fiscal 2012,2015, our anticipated cash requirements include: (i) maintenance and growth capital expenditures of approximately $22.0$34.0 million; (ii) approximately $26.2$79.4 million of interest and income tax payments; and (iii) approximately $211.6 million of distributions to Unitholders, assuming distributions remain at the current annualized levelrate of $3.41$3.50 per Common Unit, approximately $121.2 million of distributions to Unitholders.Unit. Based on our current cash position of $92.6 million as of September 27, 2014 and availability under the Revolving Credit AgreementFacility (unused borrowing capacity of $95.1$255.1 million at September 24, 2011)27, 2014) and expected cash flow from operating activities, we expect to have sufficient funds to meet our current and future obligations. Based on our current forecast of working capital requirements for fiscal 2012, we currently do not expect to borrow under our credit facility to fund those requirements.

Fiscal Year 20112014 Compared to Fiscal Year 20102013

Revenues

                 
              Percent 
  Fiscal  Fiscal  Increase/  Increase/ 
(Dollars in thousands) 2011  2010  (Decrease)  (Decrease) 
Revenues                
Propane $929,492  $885,459  $44,033   5.0%
Fuel oil and refined fuels  139,572   135,059   4,513   3.3%
Natural gas and electricity  84,721   77,587   7,134   9.2%
All other  36,767   38,589   (1,822)  (4.7%)
              
Total revenues $1,190,552  $1,136,694  $53,858   4.7%
              

(Dollars in thousands)  Fiscal
2014
   Fiscal
2013
   Increase /
(Decrease)
  Percent
Increase /
(Decrease)
 

Revenues

       

Propane

  $1,606,840    $1,357,102    $249,738    18.4

Fuel oil and refined fuels

   194,684     208,957     (14,273  (6.8%) 

Natural gas and electricity

   87,093     79,432     7,661    9.6

All other

   49,640     58,115     (8,475  (14.6%) 
  

 

 

   

 

 

   

 

 

  

 

 

 

Total revenues

  $1,938,257    $1,703,606    $234,651    13.8
  

 

 

   

 

 

   

 

 

  

 

 

 

Total revenues increased $53.9$234.7 million, or 4.7%13.8%, to $1,190.6 million in fiscal 2011 compared to $1,136.7$1,938.3 million for fiscal 2010,2014 compared to $1,703.6 million for the prior year due to higher average propane, fuel oil and refined fuels and natural gas selling prices, associated with higher product costs, partially offset to an extent by lower volumes sold. From a weather perspective,As discussed above, average temperatures as(as measured in heating degree days, as reported by the National Oceanic and Atmospheric Administration (“NOAA”), indays) across all of our service territories for fiscal 2014 were 3% colder than normal, compared to 4% warmer than normal in the prior year. However, the weather pattern during the fiscal 20112014 heating season was characterized by warmer than normal temperatures for the first two months of the period, followed by significantly colder than normal temperatures for the remainder of the heating season. In addition, during the peak of our heating season, we experienced considerably colder than normal temperatures in our east and midwest service territories, but sustained unseasonably warm temperatures in our western territories. Average temperatures in our western territories during the fiscal 2014 heating season were 1%11% warmer than normal and 4% colder6% warmer than the comparable prior year.

year period.

29


Revenues from the distribution of propane and related activities of $929.5$1,606.8 million for fiscal 20112014 increased $44.0$249.7 million, or 5.0%18.4%, compared to $885.5$1,357.1 million for fiscal 2010,the prior year, primarily as a result ofdue to higher average retail selling prices associated with higher productwholesale propane costs, partially offset by lowera decrease in retail propane volumes sold. Average propane selling prices infor fiscal 20112014 increased 8.9%20.0% compared to the prior year due toas a result of higher productwholesale propane costs, thereby havingresulting in a positive impact on revenues. This$254.6 million increase was partially offset by lower retailin revenues year-over-year. Retail propane gallons sold in fiscal 2011 which2014 decreased 19.03.9 million gallons, or 6.0%0.7%, to 298.9530.7 million gallons from 317.9534.6 million gallons in the prior year. The volume decline was primarily due to customerVolumes sold during fiscal 2014 were adversely affected by supply constraints resulting from industry-wide supply shortages and logistics issues adversely affecting propane transportation sourcing and costs that persisted throughout much of our heating season. Customer conservation efforts attributable to the high commodity price environment and ongoing sluggish economic conditions. Additionally, includedsignificant rise in propane prices also adversely affected volumes sold. Lower retail propane volumes sold resulted in a decrease in revenues of $9.3 million for fiscal 2014 compared to the prior year. Included within the propane segment are revenues from other propane activities of $76.4$79.1 million infor fiscal 2011,2014, which increased $23.8$4.4 million compared to the prior year as a result of the settlement of certain contracts used for risk management purposes (see similar increase in cost of products sold).
year.

Revenues from the distribution of fuel oil and refined fuels of $139.6$194.7 million for fiscal 2011 increased $4.52014 decreased $14.3 million, or 3.3%6.8%, from $135.1$209.0 million for the prior year, primarily due to lower volumes sold, partially offset by higher average selling prices. Fuel oil and refined fuels gallons sold in fiscal 2014 decreased 4.6 million gallons, or 8.6%, to 49.1 million gallons from 53.7 million gallons in the prior year, primarily asdue to a resultdecline in lower margin gasoline and diesel volumes. Lower fuel oil and refined fuels volumes sold resulted in a decrease in revenues of higher average selling prices associated with higher product costs, partially offset by lower volumes sold.$18.0 million for fiscal 2014 compared to the prior year. Average selling prices in our fuel oil and refined fuels segment in fiscal 20112014 increased 20.1%2.0% compared to the prior year, due to higher product costs, thereby havingresulting in a positive impact on revenues. Fuel oil and refined fuels gallons sold$3.7 million increase in fiscal 2011 decreased 6.0 million gallons, or 13.8%, to 37.2 million gallons from 43.2 million gallons in the prior year. Lower volumes sold in our fuel oil and refined fuels segment were primarily attributable to our gasoline and diesel businesses and, to a lesser extent, our heating oil business.

revenues year-over-year.

Revenues in our natural gas and electricity segment increased $7.1$7.7 million, or 9.2%9.6%, to $84.7$87.1 million in fiscal 20112014 compared to $77.6$79.4 million in the prior year as a result of higher average selling prices for natural gas and toelectricity as a lesser extent, electricity volumes sold, coupled withresult of higher average selling prices associated with higher product costs.

wholesale costs, partially offset by lower electricity usage.

Cost of Products Sold

                 
              Percent 
  Fiscal  Fiscal  Increase/  Increase/ 
(Dollars in thousands) 2011  2010  (Decrease)  (Decrease) 
Cost of products sold                
Propane $506,481  $436,825  $69,656   15.9%
Fuel oil and refined fuels  100,908   92,037   8,871   9.6%
Natural gas and electricity  61,495   57,892   3,603   6.2%
All other  9,835   11,697   (1,862)  (15.9%)
              
Total cost of products sold $678,719  $598,451  $80,268   13.4%
              
                 
As a percent of total revenues  57.0%  52.6%        

(Dollars in thousands)  Fiscal
2014
  Fiscal
2013
  Increase /
(Decrease)
  Percent
Increase /
(Decrease)
 

Cost of products sold

     

Propane

  $844,855   $612,240   $232,615    38.0

Fuel oil and refined fuels

   155,773    172,022    (16,249  (9.4%) 

Natural gas and electricity

   64,448    55,995    8,453    15.1

All other

   15,674    21,648    (5,974  (27.6%) 
  

 

 

  

 

 

  

 

 

  

Total cost of products sold

  $1,080,750   $861,905   $218,845    25.4
  

 

 

  

 

 

  

 

 

  

As a percent of total revenues

   55.8  50.6  

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

 

30


CostIn the commodities markets, propane prices were extremely volatile during fiscal 2014 as a result of products sold increased $80.3 million, or 13.4%, to $678.7 million in fiscal 2011 compared to $598.4 millionthe supply and logistics issues that started late in the prior year due to higherfirst fiscal quarter and continued throughout most of the second quarter. Overall, average product costs resulting from the increase in commodity prices, partially offset by lower volumes sold. Average posted prices for propane andfor fiscal 2014 were 24.8% higher than the prior year while fuel oil in fiscal 2011prices were 26.7% and 36.6% higher, respectively, compared to2.1% lower than the prior year. Cost of products sold in fiscal 2011 included a $1.4 million unrealized (non-cash) gain representing theThe net change in the fair value of derivative instruments during the period compared to a $5.4 millionresulted in unrealized (non-cash) lossgains of $0.3 million and unrealized (non-cash) losses of $4.3 million reported in the prior yearcost of products sold in fiscal 2014 and 2013, respectively, resulting in a decrease of $6.8$4.6 million in cost of products sold in fiscal 20112014 compared to the prior year, ($0.3$4.4 million decreaseof which was reported withinin the propane segment and $6.5 million decrease reported within the fuel oil and refined fuels segment).
segment.

Cost of products sold associated with the distribution of propane and related activities of $506.5$844.9 million for fiscal 20112014 increased $69.7$232.6 million, or 15.9%38.0%, compared to the prior year.year primarily due to higher wholesale costs and higher transportation costs associated with the extraordinary measures we took to ensure adequate propane supplies were delivered to our customer service centers to meet customer demand during the heating season. Higher average propane product costs resulted in an increase of $70.9$233.3 million, in cost of products sold during fiscal 2011 compared to the prior year. The impact of the increase in average propane product costs was partially offset by a decrease of $4.3 million related to lower propane volumes sold which resulted in a $25.5 million decrease in cost of products sold during fiscal 20112014 compared to the prior year. Cost of products sold from other propane activities increased $24.6 in fiscal 2011 compared to the prior year.

$8.0 million.

Cost of products sold associated with our fuel oil and refined fuels segment of $100.9$155.8 million for fiscal 2011 increased $8.92014 decreased $16.2 million, or 9.6%9.4%, compared to the prior year. Higher average fuel oil and refined fuel product costs resulted in an increase of $27.3 million in cost of products sold during fiscal 2011 compared to the prior year. The impact of the increase in product costs was partially offset by lowerLower fuel oil and refined fuels volumes sold whichcoupled with lower wholesale costs resulted in an $11.9decreases of $14.8 million decreaseand $1.4 million, respectively, in costcosts of products sold induring fiscal 20112014 compared to the prior year.

Cost of products sold in our natural gas and electricity segment of $61.5$64.4 million for fiscal 20112014 increased $3.6$8.5 million, or 6.2%15.1%, compared to the prior year, primarily due to higher natural gas and to a lesser extent, electricity wholesale costs, partially offset by lower volumes sold, coupled with an increase in average product costs.

Costsold.

Total cost of products sold as a percent of total revenues for fiscal 2011 increased 4.45.2 percentage points to 57.0%55.8% in fiscal 2014 from 52.6%50.6% in the prior year. The increaseyear, primarily due to the rise in cost of products sold as a percentage of revenues was primarily attributable to wholesale productpropane costs rising at a faster rate thanoutpacing the rise in propane average selling prices induring fiscal 2011 compared to the prior year.

2014.

Operating Expenses

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

(Dollars in thousands)  Fiscal
2014
  Fiscal
2013
  Decrease  Percent
Decrease
 

Operating expenses

  $466,389   $469,496   $(3,107  (0.7%) 

As a percent of total revenues

   24.1  27.6  

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

Operating expenses of $279.3$466.4 million for fiscal 20112014 decreased $10.2$3.1 million, or 3.5%0.7%, compared to $289.6$469.5 million in the prior year, primarily due to synergies realized as a result of lower variable compensationthe continuing integration of Inergy Propane operations, which was offset to an extent by higher overtime and vehicle expenses attributable to harsh weather conditions during our fiscal 2014 heating season, as well as higher provisions for potential uncollectible accounts. Operating expenses for fiscal 2014 included integration-related expenses of $8.1 million associated with lower earnings, lower payrollthe integration of the Inergy Propane operations compared to $4.6 million in the prior year. In addition, fiscal 2013 included a $7.0 million charge related to our voluntary partial withdrawal from a multi-employer pension plan and benefit related expenses resultingfull withdrawal from operating efficiencies, and lower insurance costs.four multi-employer pension plans for certain employees acquired in the Inergy Propane Acquisition. These savingscharges were partially offset by an increase in fuel costs to operateexcluded from our fleet.

calculation of Adjusted EBITDA below.

31


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

(Dollars in thousands)  Fiscal
2014
  Fiscal
2013
  Decrease  Percent
Decrease
 

General and administrative expenses

  $64,593   $64,845   $(252  (0.4%) 

As a percent of total revenues

   3.3  3.8  

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

General and administrative expenses of $51.6$64.6 million for fiscal 2011 decreased $10.0 million, or 16.2%,2014 was relatively flat compared to $61.6the prior year. General and administrative expenses for fiscal 2014 and 2013 included $4.2 million and $6.0 million, respectively, of professional services and other expenses associated with the integration of the Inergy Propane operations. These items were excluded from our calculation of Adjusted EBITDA below.

Depreciation and Amortization

(Dollars in thousands)  Fiscal
2014
  Fiscal
2013
  Increase   Percent
Increase
 

Depreciation and amortization

  $136,399   $130,384   $6,015     4.6

As a percent of total revenues

   7.0  7.7   

Depreciation and amortization expense of $136.4 million in fiscal 2014 increased $6.0 million, primarily as a result of depreciation expense on buildings, vehicles and equipment taken out of service as a result of the integration of Inergy Propane operations.

Interest Expense, net

(Dollars in thousands)  Fiscal
2014
  Fiscal
2013
  Decrease  Percent
Decrease
 

Interest expense, net

  $83,261   $95,427   $(12,166  (12.7%) 

As a percent of total revenues

   4.3  5.6  

Net interest expense of $83.3 million for fiscal 2014 decreased $12.2 million compared to $95.4 million in the prior year, primarily asdue to the reduction of $157.3 million in long-term borrowings during the fourth quarter of fiscal 2013 and, to a result of lower variable compensation associated with lower earnings andlesser extent, the impact of a $2.5 million gain on salethe refinancing of assetsour 7.5% Senior Notes due 2018 with 5.5% Senior Notes due 2024 completed during the secondthird quarter of fiscal 2011, partially offset by an increase in litigation costs for uninsured legal matters.

Depreciation and Amortization
                 
  Fiscal  Fiscal      Percent 
(Dollars in thousands) 2011  2010  Increase  Increase 
Depreciation and amortization $35,628  $30,834  $4,794   15.5%
As a percent of total revenues  3.0%  2.7%        
Depreciation and amortization expense of $35.6 million in fiscal 2011 increased $4.8 million, or 15.5%, compared to $30.8 million in the prior year primarily as a result of tangible and intangible long-lived assets acquired in business combinations in fiscal 2011 and 2010, coupled with accelerated depreciation expense of $2.9 million and $1.8 million in fiscal 2011 and fiscal 2010, respectively, for assets taken out of service.
Interest Expense, net
                 
  Fiscal  Fiscal      Percent 
(Dollars in thousands) 2011  2010  (Decrease)  (Decrease) 
Interest expense, net $27,378  $27,397  $(19)  (0.1%)
As a percent of total revenues  2.3%  2.4%        
Net interest expense of $27.4 million in fiscal 2011 was flat compared to the prior year.2014. See Liquidity and Capital Resources below for additional discussion on long-term borrowings.

discussion.

32


Loss on Debt Extinguishment

On March 23, 2010,May 27, 2014, we repurchased $250.0 million aggregate principal amountand satisfied and discharged all of our 2018 Senior Notes with net proceeds from the issuance of the 20132024 Senior Notes throughand cash on hand pursuant to a cash tender offer.offer and redemption. In connection with the repurchase,this tender offer and redemption, we recognized a loss on the extinguishment of debt of $9.5$11.6 million consisting of $31.6 million for the redemption premium and related fees, as well as the write-off of $5.3 million and ($25.3) million in unamortized debt origination costs and unamortized premium, respectively.

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 second quarterunderwriters’ exercise of fiscal 2010,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 $7.2$11.7 million for the repurchase premium and related fees, as well as the write-off of $2.3$2.1 million and ($11.7) million in unamortized debt origination costs and unamortized discount.

premium, respectively.

Net Income and Adjusted EBITDA

We reported net

Net income of $115.0for fiscal 2014 amounted to $94.5 million, or $3.24$1.56 per Common Unit, compared to $78.8 million, or $1.35 per Common Unit, in fiscal 20112013. Earnings before interest, taxes, depreciation and amortization (“EBITDA”) for fiscal 2014 amounted to $314.9 million, compared to net income of $115.3$305.2 million or $3.26 per Common Unit in the prior year. Adjusted EBITDA amounted to $179.4 million infor fiscal 2011, compared to $192.4 million in fiscal 2010.

2013.

Net income and EBITDA for fiscal 2011 were negatively impacted by a $2.02014 included: (i) $12.3 million charge for severance costs associated with a realignmentin expenses related to the ongoing integration of our field operations, as well as a non-cash charge of $2.9 to accelerate depreciation expense on assets taken out of service. By comparison, net incomeInergy Propane and EBITDA for fiscal 2010 were negatively impacted by certain items, including: (i)(ii) a loss on debt extinguishment of $9.5$11.6 million. Net income and EBITDA for fiscal 2013 included: (i) $10.6 million associated within expenses related to the refinancingongoing integration of senior notes;Inergy Propane; (ii) a non-cash$7.0 million in charges related to our voluntary withdrawal from multi-employer pension settlement charge of $2.8 million;plans covering certain employees acquired in the Inergy Propane Acquisition; and (iii) a non-cash chargeloss on debt extinguishment of $1.8$2.1 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 $338.5 million for fiscal 2014, compared to accelerate depreciation expense on assets taken outAdjusted EBITDA of service.

$329.3 million in fiscal 2013.

Adjusted EBITDA represents EBITDA excluding the unrealized net gain or loss from mark-to-market activity for derivative instruments loss on debt extinguishment, pension settlement charge and severance charges.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. In addition, certain of our incentive compensation plans covering executives and other employees utilize Adjusted EBITDA as the performance target. Moreover, our revolving credit agreement requires us to use Adjusted EBITDA as a component in calculating our leverage and interest coverage ratios. EBITDA and Adjusted EBITDA are not recognized terms under US GAAP and should not be considered as an alternative to net income or net cash provided by operating activities determined in accordance with US GAAP. Because EBITDA and Adjusted EBITDA as determined by us excludes some, but not all, items that affect net income, they may not be comparable to EBITDA and Adjusted EBITDA or similarly titled measures used by other companies.

33


The following table sets forth (i) our calculations of EBITDA and adjusted EBITDA and (ii) a reconciliation of both EBITDA and adjusted EBITDA, as so calculated, to our net cash provided by operating activities:
         
  Year Ended 
  September 24,  September 25, 
(Dollars in thousands) 2011  2010 
         
Net income $114,966  $115,316 
Add:        
Provision for income taxes  884   1,182 
Interest expense, net  27,378   27,397 
Depreciation and amortization  35,628   30,834 
       
EBITDA  178,856   174,729 
Unrealized (non-cash) (gains) losses on changes in fair value of derivatives  (1,431)  5,400 
Severance charges  2,000    
Loss on debt extinguishment     9,473 
Pension settlement charge     2,818 
       
Adjusted EBITDA  179,425   192,420 
Add (subtract):        
Provision for income taxes — current  (884)  (1,182)
Interest expense, net  (27,378)  (27,397)
Unrealized (non-cash) gains (losses) on changes in fair value of derivatives  1,431   (5,400)
Severance charges  (2,000)   
Compensation cost recognized under Restricted Unit Plans  3,922   4,005 
(Gain) loss on disposal of property, plant and equipment, net  (2,772)  38 
Changes in working capital and other assets and liabilities  (18,958)  (6,687)
       
         
Net cash provided by operating activities $132,786  $155,797 
       
activities

   Year Ended 
(Dollars in thousands)  September 27,
2014
  September 28,
2013
 

Net income

  $94,509   $78,798  

Add:

   

Provision for income taxes

   767    607  

Interest expense, net

   83,261    95,427  

Depreciation and amortization

   136,399    130,384  
  

 

 

  

 

 

 

EBITDA

   314,936    305,216  

Unrealized (non-cash) (gains) losses on changes in fair value of derivatives

   (306  4,318  

Integration-related costs

   12,283    10,575  

Loss on debt extinguishment

   11,589    2,144  

Multi-employer pension plan withdrawal charge

   —      7,000  
  

 

 

  

 

 

 

Adjusted EBITDA

   338,502    329,253  

Add (subtract):

   

Provision for income taxes

   (767  (607

Interest expense, net

   (83,261  (95,427

Unrealized (non-cash) gains (losses) on changes in fair value of derivatives

   306    (4,318

Integration-related costs

   (12,283  (10,575

Multi-employer pension plan withdrawal charge

   —      (7,000

Compensation cost recognized under Restricted Unit Plans

   7,390    3,888  

Gain on disposal of property, plant and equipment, net

   (521  (3,543

Changes in working capital and other assets and liabilities

   (23,815  2,635  
  

 

 

  

 

 

 

Net cash provided by operating activities

  $225,551   $214,306  
  

 

 

  

 

 

 

Fiscal Year 20102013 Compared to Fiscal Year 20092012

Revenues

                 
              Percent 
  Fiscal  Fiscal  Increase/  Increase/ 
(Dollars in thousands) 2010  2009  (Decrease)  (Decrease) 
Revenues                
Propane $885,459  $864,012  $21,447   2.5%
Fuel oil and refined fuels  135,059   159,596   (24,537)  (15.4)%
Natural gas and electricity  77,587   76,832   755   1.0%
All other  38,589   42,714   (4,125)  (9.7)%
              
Total revenues $1,136,694  $1,143,154  $(6,460)  (0.6)%
              

 

(Dollars in thousands)  Fiscal
2013
   Fiscal
2012
   Increase   Percent
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
  

 

 

   

 

 

   

 

 

   

34


Total revenues decreased $6.5increased $640.1 million, or 0.6%60.2%, to $1,136.7$1,703.6 million for the year ended September 25, 2010fiscal 2013 compared to $1,143.2$1,063.5 million for the year ended September 26, 2009, due to lower volumes, partially offset by higher average selling prices associated with higher product costs. Volumes for the fiscal 2010 were lower than the prior year due to 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 negative impactaddition of adverse economic conditions, particularly on our commercial and industrial accounts,the Inergy Propane business, as well as the unfavorable impact of warmerincreases in our legacy operations resulting from colder average temperatures. As discussed above, average temperatures particularly in our northeastern and western service territories, and ongoing residential customer conservation. From a weather perspective, average temperatures as(as measured in heating degree days, as reported by NOAA, indays) across all of our service territories duringfor fiscal 20102013 were 5%4% warmer than normal, and 4%compared to 14% warmer than normal for the prior year. In our northeastern territories, which is where we have a higher concentration of residential propane customers and all of our fuel oil customers, average temperatures during fiscal 2010 were 9% warmer than both normal and the prior year. The unfavorable weather pattern occurred primarily during the peak heating months (from October through March) and therefore, contributed to the lower volumes sold.

Revenues from the distribution of propane and related activities of $885.5$1,357.1 million for fiscal 2013 increased $513.5 million, or 60.9%, compared to $843.6 million for the prior year, ended September 25, 2010primarily 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 $21.4250.8 million gallons, or 2.5%88.4%, compared to $864.0534.6 million forgallons from 283.8 million gallons in the prior year, ended September 26, 2009, primarily as a result of higher average selling prices associated with higher product costs, partially offset by lower volumes, particularlythe addition of Inergy Propane, as well as increases in our commercial and industrial accounts.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 infor fiscal 2010 increased 9.8%2013 decreased 11.5% compared to the prior year due to higherlower wholesale product costs, thereby havingresulting in a positive impact on revenues. This increase was partially offset by lower retail propane gallons sold$166.9 million decrease in fiscal 2010 which decreased 26.0 million gallons, or 7.6%, to 317.9 million gallons from 343.9 million gallons in the prior year. The volume decline was primarily attributable to lower commercial and industrial volumes resulting from adverse economic conditions, an unfavorable weather pattern and, to a lesser extent, continued residential customer conservation. Lower volumes sold in the non-residential customer base accounted for approximately 60% of the decline in propane sales volume. Additionally, includedrevenues year-over-year. Included within the propane segment are revenues from wholesalerisk management activities and other propane activities of $52.7$74.7 million infor fiscal 2010,2013, which increased $9.3$0.6 million compared to the prior year.

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 $135.1$209.0 million for the year ended September 25, 2010 decreased $24.5fiscal 2013 increased $94.7 million, or 15.4%82.8%, from $159.6$114.3 million infor the prior year, primarily due to lowerhigher volumes sold, partially offset by higherlower average selling prices. Fuel oil and refined fuels gallons sold in fiscal 2010 decreased 14.22013 increased 25.2 million gallons, or 24.7%88.4%, to 43.253.7 million gallons from 57.428.5 million gallons in the prior year. Lower volumesyear, 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 segment were attributablevolumes sold resulted in an increase in revenues of $100.5 million for fiscal 2013 compared to the aforementioned warmer average temperatures in the northeast region, as well as the impact of ongoing residential customer conservation driven by adverse economic conditions.prior year. Average selling prices in our fuel oil and refined fuels segment in fiscal 2010 increased 12.2%2013 decreased 2.6% compared to the prior year, due to higher product costs, thereby havingresulting in a positive impact on revenues.

$5.8 million decrease in revenues year-over-year.

Revenues in our natural gas and electricity segment increased $0.8$12.0 million, or 1.0%17.8%, to $77.6$79.4 million for the year ended September 25, 2010in fiscal 2013 compared to $76.8$67.4 million in the prior year as a result of higher electricity volumes, partially offset by lower natural gas volumes. Revenuesvolumes sold, and higher electricity average selling prices. The increase in our all other businesses decreased 9.7%volumes sold was primarily attributable to $38.6 millionthe more favorable weather pattern in fiscal 2010 from $42.7 million2013, compared to the unseasonably warm weather in the prior year, primarily due to reduced installation service activities as a result of the general market decline in residential and commercial construction and other adverse economic conditions.

year.

35


Cost of Products Sold
                 
              Percent 
  Fiscal  Fiscal  Increase/  Increase/ 
(Dollars in thousands) 2010  2009  (Decrease)  (Decrease) 
Cost of products sold                
Propane $436,825  $367,016  $69,809   19.0%
Fuel oil and refined fuels  92,037   104,634   (12,597)  (12.0)%
Natural gas and electricity  57,892   57,216   676   1.2%
All other  11,697   11,519   178   1.5%
              
Total cost of products sold $598,451  $540,385  $58,066   10.7%
              
                 
As a percent of total revenues  52.6%  47.3%        
Cost

(Dollars in thousands)  Fiscal
2013
  Fiscal
2012
  Increase   Percent
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   
      

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 $58.1$262.8 million, or 10.7%43.9%, to $598.5$861.9 million for the year ended September 25, 2010in fiscal 2013 compared to $540.4$599.1 million in the prior year due to higher average product costs and, to a lesser extent, the unfavorable impact of non-cash mark-to-market adjustments from our risk management activities in fiscal 2010 compared to the prior year,volumes sold, partially offset by lower volumes sold. Average posted prices foraverage propane and fuel oil in fiscal 2010 were 46.3% and 26.1% higher, respectively, compared to the prior year. Cost of products sold in fiscal 2010 included a $5.4 million unrealized (non-cash) loss representing theproduct costs. The net change in the fair value of derivative instruments during the period compared to a $1.7 millionresulted in unrealized (non-cash) gainlosses of $4.3 million and unrealized (non-cash) gains of $4.6 million reported in the prior yearcost of products sold in fiscal 2013 and 2012, respectively, resulting in an increase of $7.1$8.9 million in cost of products sold in fiscal 20102013 compared to the prior year, ($1.3 million decreaseall of which was reported withinin the propane segment and $8.4 million increase reported within the fuel oil and refined fuels segment).

segment.

Cost of products sold associated with the distribution of propane and related activities of $436.8$612.2 million for the year ended September 25, 2010fiscal 2013 increased $69.8$164.1 million, or 19.0%36.6%, compared to the prior year. Higher retail propane product costsvolumes sold resulted in an increase of $89.2$368.4 million in cost of products sold induring fiscal 20102013 compared to the prior year. ThisThe impact of the increase in volumes sold was partially offset by lower average propane volumes,costs, which resulted in a $190.0 million decrease of $27.5 million in cost of products sold in fiscal 2010 compared to the prior year.year-over-year. Cost of products sold from wholesale and other propane activities increased $9.4decreased $23.2 million in fiscal 2013 compared to the prior year.

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 $92.0$172.0 million for the year ended September 25, 2010 decreased $12.6fiscal 2013 increased $80.8 million, or 12.0%88.5%, compared to the prior year primarily due to lower volumes, offset to an extent by higher product costs and the unfavorable impact of non-cash mark-to-market adjustments from our risk management activities. Lower fuel oil and refined fuels volumes resulted in a decrease of $26.2 million in cost of products sold, and higher product costs resulted in an increase of $5.2 million in cost of products sold during fiscal 2010 compared to the prior year.

sold.

Cost of products sold in our natural gas and electricity segment of $57.9$56.0 million for the year ended September 25, 2010fiscal 2013 increased $0.6$9.1 million, or 1.2%19.4%, compared to the prior year, primarily due to higher electricity volumes, partially offset by lower natural gas volumes. Cost of productsvolumes sold, in our all other businesses of $11.7 million was relatively flat compared to the prior year.

For fiscal 2010, totaland higher electricity product costs.

Total cost of products sold as a percent of total revenues increased 5.3decreased 5.7 percentage points to 52.6% from 47.3% in the prior year. The year-over-year increase in cost of products sold as a percentage of revenues was primarily attributable to the favorable margins reported in the prior year that were attributable to the declining commodity price environment during that period, which situation was not repeated in the current year due to the rising commodity price environment in the current year. The declining commodity price environment in the prior year favorably impacted our risk management activities50.6% in fiscal 2009, and contributed to a reduction in product costs that outpaced the decline in average selling prices. Conversely, the volatile and rising commodity price environment in the current fiscal year presented challenges in managing pricing and, as a result, average product costs increased at a faster pace than average selling prices in fiscal 2010.

36


Operating Expenses
                 
  Fiscal  Fiscal      Percent 
(Dollars in thousands) 2010  2009  (Decrease)  (Decrease) 
Operating expenses $289,567  $304,767  $(15,200)  (5.0)%
As a percent of total revenues  25.5%  26.7%        
Operating expenses of $289.6 million for the year ended September 25, 2010 decreased $15.2 million, or 5.0%, compared to $304.8 million in the prior year as a result of lower variable compensation associated with lower earnings, lower payroll and benefit related expenses resulting2013 from operating efficiencies, and lower insurance costs.
General and Administrative Expenses
                 
  Fiscal  Fiscal      Percent 
(Dollars in thousands) 2010  2009  Increase  Increase 
General and administrative expenses $61,656  $57,044  $4,612   8.1%
As a percent of total revenues  5.4%  5.0%        
General and administrative expenses of $61.6 million for the year ended September 25, 2010 increased $4.6 million, or 8.1%, compared to $57.0 million during the prior year as savings from lower variable compensation associated with lower earnings were more than offset by an unfavorable judgment in a legal matter and an increase in accruals for uninsured legal matters, as well as higher advertising costs.
Depreciation and Amortization
                 
  Fiscal  Fiscal      Percent 
(Dollars in thousands) 2010  2009  Increase  Increase 
Depreciation and amortization $30,834  $30,343  $491   1.6%
As a percent of total revenues  2.7%  2.7%        
Depreciation and amortization expense of $30.8 million for the year ended September 25, 2010 increased $0.5 million, or 1.6%, compared to $30.3 million56.3% in the prior year, primarily asdue 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 resulthigher concentration of accelerating depreciation expenseresidential volumes sold in fiscal 2013 compared to the third quarter of fiscal 2010 for certain assets retired.
prior year, which had a favorable impact on overall gross margins.

Operating Expenses

 

(Dollars in thousands)  Fiscal
2013
  Fiscal
2012
  Increase   Percent
Increase
 

Operating expenses

  $469,496   $298,772   $170,724     57.1

As a percent of total revenues

   27.6  28.1   

37


Interest Expense, net
                 
  Fiscal  Fiscal      Percent 
(Dollars in thousands) 2010  2009  (Decrease)  (Decrease) 
Interest expense, net $27,397  $38,267  $(10,870)  (28.4)%
As a percent of total revenues  2.4%  3.3%        
Net interest expense decreased $10.9Operating expenses of $469.5 million for fiscal 2013 increased $170.7 million, or 28.4%57.1%, to $27.4 million for the year ended September 25, 2010, compared to $38.3$298.8 million in the prior year, primarily due to the reductionaddition of $183.0Inergy 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
2013
  Fiscal
2012
  Increase   Percent
Increase
 

General and administrative expenses

  $64,845   $59,020   $5,825     9.9

As a percent of total revenues

   3.8  5.5   

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 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
2013
  Fiscal
2012
  Increase   Percent
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 long-term borrowings duringfiscal 2013 increased $83.4 million, primarily as a result of the second halfacquired tangible and identifiable intangible assets of Inergy Propane.

Interest Expense, net

(Dollars in thousands)  Fiscal
2013
  Fiscal
2012
  Increase   Percent
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 2009, coupled2013 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 a lower effective interest rate for borrowings under our revolving credit facility.the Inergy Propane Acquisition on August 1, 2012. See Liquidity and Capital Resources below for additional discussion on the reduction and changes in long-term borrowings.

discussion.

Loss on Debt Extinguishment

On March 23, 2010,August 2, 2013, we repurchased, $250.0pursuant to an optional redemption, $133.4 million aggregate principal amount 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, Senior Notes throughwe repurchased $23.9 million of our 2021 senior notes in a private transaction using cash tender offer.on hand. In connection with the repurchase,these repurchases, which totaled $157.3 million in aggregate principal amount, we recognized a loss on the extinguishment of debt of $9.5$2.1 million in the second quarter of fiscal 2010, consisting of $7.2$11.7 million for the repurchase premium and related fees, as well as the write-off of $2.3$2.1 million and ($11.7) million in unamortized debt origination costs and unamortized discount.

On September 9, 2009, we purchased $175.0 million aggregate principal amount of the 2013 Senior Notes through a cash tender offer. Inpremium, respectively.

During fiscal 2012, in connection with the repurchase,execution of the amendment of our credit agreement on January 5, 2012, we recognized a lossnon-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 extinguishmentInergy Propane Acquisition, we recognized a non-cash charge of $1.7 million to write off unamortized debt of $4.6 million inorigination costs associated with the 364-Day Facility during the fourth quarter of fiscal 2009, consisting of $2.8 million2012. See Liquidity and Capital Resources below for additional discussion on the tender premiumamendment to the credit agreement and related fees, as well as the write-off of $1.8 million in unamortized debt origination costs and unamortized discount.

other financing activities.

Net Income and Adjusted EBITDA

We reported net

Net income of $115.3for fiscal 2013 amounted to $78.8 million, or $3.26$1.35 per Common Unit, for the year ended September 25, 2010 compared to net income of $165.2$0.6 million, or $4.99$0.02 per Common Unit, in the prior year. Adjusted EBITDAfiscal 2012. Earnings before interest, taxes, depreciation and amortization (“EBITDA”) for fiscal 2013 amounted to $192.4$305.2 million, compared to $239.2$86.4 million for fiscal 2009.

2012.

Net income and EBITDA for fiscal 2010 were negatively impacted by2013 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 items, including: (i)employees acquired in the Inergy Propane Acquisition; and (iii) a loss on debt extinguishment of $9.5 million associated with the refinancing of senior notes completed during the second quarter; (ii) a non-cash pension settlement charge of $2.8 million during the fourth quarter; and (iii) a non-cash charge of $1.8 million during the third quarter to accelerate depreciation expense on certain assets taken out of service.$2.1 million. Net income and EBITDA for fiscal 2009 included2012 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 $4.6$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 associated with the debt tender offer completed during the fourth quarterfor fiscal 2013, compared to Adjusted EBITDA of $108.5 million in fiscal 2009.

2012.

38


The following table sets forth (i) our calculations of EBITDA and adjusted EBITDA and (ii) a reconciliation of both EBITDA and adjusted EBITDA, as so calculated, to our net cash provided by operating activities:
         
  Year Ended 
  September 25,  September 26, 
(Dollars in thousands) 2010  2009 
         
Net income $115,316  $165,238 
Add:        
Provision for income taxes  1,182   2,486 
Interest expense, net  27,397   38,267 
Depreciation and amortization  30,834   30,343 
       
EBITDA  174,729   236,334 
Unrealized (non-cash) losses (gains) on changes in fair value of derivatives  5,400   (1,713)
Loss on debt extinguishment  9,473   4,624 
Pension settlement charge  2,818    
       
Adjusted EBITDA  192,420   239,245 
Add (subtract):        
Provision for income taxes — current  (1,182)  (1,101)
Interest expense, net  (27,397)  (38,267)
Unrealized (non-cash) (losses) gains on changes in fair value of derivatives  (5,400)  1,713 
Compensation cost recognized under Restricted Unit Plans  4,005   2,396 
Loss (gain) on disposal of property, plant and equipment, net  38   (650)
Changes in working capital and other assets and liabilities  (6,687)  43,215 
       
         
Net cash provided by operating activities $155,797  $246,551 
       

   Year Ended 
(Dollars in thousands)  September 28,
2013
  September 29,
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    —    

Loss on debt extinguishment

   2,144    2,249  

Multi-employer pension plan withdrawal charge

   7,000    —    

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  
  

 

 

  

 

 

 

Liquidity and Capital Resources

Analysis of Cash Flows

Operating Activities.Net cash provided by operating activities for fiscal 20112014 amounted to $132.8$225.5 million, a decreasean increase of $23.0$11.2 million compared to the prior year. The decreaseincrease was primarily attributable to a $10.6 million decreasean increase in earnings, after adjusting for non-cash items in both periods, coupled withperiods. In addition, average posted prices for propane during fiscal 2014 increased 24.8% compared to the prior year, which resulted in a $12.4 million increase in our investment in working capital as a result of the increase in propane and fuel oil product costs. Despite the year-over-yearsubstantial increase in working capital requirements we continuedyear-over-year. Cash flows from operating activities for fiscal 2013 benefited to fundan extent by the realization of working capital through cash on hand withoutacquired in the need to access the revolving credit facility.

Inergy Propane Acquisition.

Investing Activities.Net cash used in investing activities of $19.5$16.5 million for fiscal 20112014 consisted of capital expenditures of $22.3$30.1 million (including $10.2$18.2 million for maintenance expenditures and $12.1 million to support the growth of operations) and business acquisitions of $3.2 million, partially offset by the net proceeds from the sale of property, plant and equipment of $6.0 million. Net cash used in investing activities of $30.1 million for fiscal 2010 consisted of capital expenditures of $19.1 million (including $9.7 million for maintenance expenditures and $9.4$11.9 million to support the growth of operations), partially offset by the net proceeds of $13.5 million from the sale of property, plant and equipment. 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 $3.5 million.

$5.8 million from Inergy as a result of a purchase price adjustment attributable to the working capital of Inergy Propane.

39


Financing Activities.Net cash used in financing activities for fiscal 20112014 of $120.6$223.6 million reflects the quarterly distributionsdistribution to Common Unitholders at a rate of $0.85$0.8750 per Common Unit paid in respect of the fourth quarter of fiscal 20102013 and the first, second and third quarters of fiscal 2014. In addition, cash used in financing activities included proceeds of $525.0 million from the issuance of the 2024 Senior Notes in May 2014. The net proceeds from the 2024 Senior Notes offering were used, along with cash on hand, to repurchase and satisfy and discharge all of the outstanding 2018 Senior Notes, as well as to pay tender premiums and other related fees of $31.6 million and debt issuance costs of $9.5 million, pursuant to a tender offer and redemption.

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 2011.

Net2013. In addition, net cash used in financing activities for fiscal 2010 of $132.0 million reflects $118.3 million in quarterly distributions to Unitholders at a rate of $0.83 per Common Unit paid in respect of the fourth quarter of fiscal 2009, $0.835 per Common Unit paid in respect of the first quarter of fiscal 2010, $0.84 per Common Unit paid in respect of the second quarter of fiscal 2010, and $0.845 per Common Unit paid in respect of the third quarter of fiscal 2010. In addition, financing activities for fiscal 2010 also reflects the repurchase of $250.0 million aggregate principal amount of our 6.875% senior notes due 2013 for $256.5 million (including repurchase premiums and fees), which was substantially funded by the netincludes proceeds of $247.8$143.4 million from the issuance of 7.375% senior notes due 2020, as well as3,105,000 of our Common Units in May 2013. The net proceeds from the $5.0equity offering, along with cash on hand, were used to redeem $157.3 million payment of debt issuance costs associated with the issuance of the 2020 senior notes.
our 2021 Senior Notes in August 2013.

Equity Offering

On August 10, 2009,May 17, 2013, we sold 2,200,0002,700,000 Common Units in a public offering (the “Equity Offering”) at a price of $41.50$48.16 per Common Unit realizing proceeds of $86.7$124.7 million, net of underwriting commissions and other offering expenses. On August 24, 2009, we announced thatMay 22, 2013, following the underwriters had given notice of theirunderwriters’ exercise of their over-allotment option, in part, to acquire 230,934we sold an additional 405,000 Common Units at the Equity Offering price of $41.50$48.16 per Common Unit. NetUnit, generating additional proceeds from the over-allotment exercise amounted to $9.2 million.of $18.7 million, net of underwriting commissions. The aggregate net proceeds from the Equity Offeringoffering, including the net proceeds from the underwriters’ exercise of $95.9 milliontheir over-allotment option, were used along with cash on hand, to fund the purchase of $175.0redeem $133.4 million aggregate principal amount of our 6.875%2021 senior notes due 2013.

in August 2013, including prepayment premiums and other expenses.

Summary of Long-Term Debt Obligations and Revolving Credit Lines

As of September 27, 2014, our long-term debt consisted of $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, $525.0 million in aggregate principal amount of 5.5% senior notes due June 1, 2024 and $100.0 million outstanding 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.

On May 27, 2014, we repurchased and satisfied and discharged all of our 2018 Senior Notes with net proceeds from the issuance of the 2024 Senior Notes, as defined below, and cash on hand, pursuant to a tender offer and redemption during the third quarter of fiscal 2014. In connection with this tender offer and redemption, we recognized a loss on the extinguishment of debt of $11.6 million consisting of $31.6 million for the redemption premium and related fees, as well as the write-off of $5.3 million and ($25.3) million in unamortized debt origination costs and unamortized premium, respectively. The 2018 Senior Notes required semi-annual interest payments in April and October, and the 2021 Senior Notes require semi-annual interest payments in February and August.

The 2021 Senior Notes are redeemable, at our option, in whole or in part, at any time on or 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 then-outstanding unregistered 7.5% senior notes due 2018 and 7.375% senior notes due 2021 (collectively, the “Old Notes”) for an equal principal amount of 7.5% senior notes due 2018 and 7.375% senior notes due 2021 (collectively, the “Exchange Notes”), respectively, that have been registered under the Securities Act of 1933, as amended. The terms of the Exchange Notes are identical in all material respects (including principal amount, interest rate, maturity and redemption rights) to the Old Notes for which they 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, wethe 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.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 on or 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

   102.458

2017

   101.229

2018 and thereafter

   100.000

2024 Senior Notes

As previously discussed, on May 27, 2014, the Partnership and its 100%-owned subsidiary, Suburban Energy Finance Corp., completed a public offering of $525.0 million in aggregate principal amount of 5.5% senior notes due June 1, 2024 (the “2024 Senior Notes”). The 2024 Senior Notes were issued at 100% of the principal amount and require semi-annual interest payments in June and December, beginning in December 2014. The net proceeds from the issuance of the 2024 Senior Notes, along with cash on hand, were used to repurchase the 6.875% senior notes due 2013 (the “2013 Senior Notes”) on March 23, 2010 through a redemption and tender offer. In connection with the repurchasesatisfy and discharge all of the 20132018 Senior Notes.

The 2024 Senior Notes we recognized a loss on the extinguishment of debt of $9.5 million in the second quarter of fiscal 2010, consisting of $7.2 million for the repurchase premium and related fees, as well as the write-off of $2.3 million in unamortized debt origination costs and unamortized discount.

As of September 24, 2011,are redeemable, at our long-term borrowings and revolving credit lines consist of the 2020 Senior Notes and a $250.0 million senior secured revolving credit facility at the Operating Partnership level (the “Revolving Credit Facility”). The Revolving Credit Facility was executed on June 26, 2009 and replaced the Operating Partnership’s previous credit facility which, as amended, provided for a $108.0 million term loan (the “Term Loan”) and a separate $175.0 million working capital facility both of which were scheduled to mature in March 2010. Borrowings under the Revolving Credit Facility may be used for general corporate purposes, including working capital, capital expenditures and acquisitions until maturity on June 25, 2013. Our Operating Partnership has the right to prepay loans under the Revolving Credit Facility,option, in whole or in part, without penalty at any time prior to maturity. At closing,on or after June 1, 2019, in each case at the Operating Partnership borrowed $100.0 million under the Revolving Credit Facility and, with cash on hand, repaid the $108.0 million then outstanding under the Term Loan and terminated the previous credit agreement. We have standby letters of credit issued under the Revolving Credit Facilityredemption prices described in the aggregate amounttable below, together with any accrued and unpaid interest to the date of $54.9 million primarily in support of retention levelsthe redemption.

Year

  Percentage 

2019

   102.750

2020

   101.833

2021

   100.917

2022 and thereafter

   100.000

Our obligations under our self-insurance programs, which expire periodically through April 15, 2012. Therefore, as of September 24, 2011 we had available borrowing capacity of $95.1 million under the Revolving Credit Facility.

The 2020 Senior Notes mature on March 15, 2020 and require semi-annual interest payments in March and September. We are permitted to redeem some or all of the 2020 Senior Notes, any time at redemption prices specified in the indenture governing the notes. In addition, the 20202021 Senior Notes and 2024 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 each have a change of control provision that would require us to offer to repurchase the notes at 101% of the principal amount repurchased, if thea 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.

40

Credit Agreement


Our Operating Partnership has an amended and restated credit agreement entered into on January 5, 2012, as amended on August 1, 2012 and May 9, 2014 (collectively, 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 27, 2014 and September 28, 2013. 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.

During the second quarter of fiscal 2014, we experienced a significant increase in working capital requirements as a result of the impact of the significant increase in wholesale propane costs. This increase in working capital requirements resulted in the net borrowing of $61.7 million under our Revolving Credit Facility during fiscal 2014. The borrowings were repaid in full during fiscal 2014 with internally generated cash.

The amendment and restatement of the credit agreement on January 5, 2012 amended the previous credit agreement to, among other things, extend the maturity date from June 25, 2013 to January 5, 2017, reduce the borrowing rate and commitment fees, and amend certain affirmative and negative covenants.

On August 1, 2012, our Operating Partnership executed an amendment to the Amended Credit Agreement to, among other things, provide for (i) a $250.0 million senior secured 364-Day Facility and (ii) an increase in our revolving credit facility under the Amended Credit Agreement from $250.0 million to $400.0 million. On the Acquisition Date, our Operating Partnership drew $225.0 million on the 364-Day Facility, which was used to fund a portion of the Inergy Propane Acquisition, including costs and expenses related to the acquisition. We repaid the $225.0 million of borrowings under the 364-Day Facility on August 14, 2012 with the net proceeds from the public issuance of Common Units on August 14, 2012.

The amendment to the Amended Credit Agreement on August 1, 2012 also amended certain restrictive and affirmative covenants applicable to our Operating Partnership and to us, as well as certain financial covenants, including (a) requiring our consolidated interest coverage ratio, as defined in the amendment, to be not less than 2.0 to 1.0 as of the end of any fiscal quarter; (b) prohibiting the total consolidated leverage ratio, as defined in the amendment, of the Partnership from being greater than 7.0 to 1.0 as of the end of any fiscal quarter. The minimum consolidated interest coverage ratio increases over time, and commencing with the second quarter of fiscal 2014, such minimum ratio is 2.5 to 1.0. The maximum consolidated leverage ratio decreases over time, as well as upon the occurrence of certain events, and, commencing with the second quarter of fiscal 2013, such maximum ratio is 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.

The second amendment to the Amended Credit Agreement on May 9, 2014 made certain technical amendments with respect to agreements relating to debt refinancing.

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 ourthe Operating Partnership’s option, LIBOR plus the applicable margin or the base rate, defined as the higher of the Federal Funds Rate plus1/2 of 1%, the agent bank’s prime rate, or LIBOR plus 1%, plus in each case the applicable margin. The applicable margin is dependent upon our ratio of total debtConsolidated Total Debt to Consolidated EBITDA, on a consolidated basis, as defined in the Revolving Credit Facility. As of September 24, 2011,27, 2014, the interest rate for the Revolving Credit Facility was approximately 3.25%2.5%. The interest rate and the applicable margin will be reset at the end of each calendar quarter.

On July 31, 2009,

In connection with the Amended Credit Agreement, our Operating Partnership entered into an interest rate swap agreement with ana June 25, 2013 effective date of March 31, 2010 and a terminationmaturity date of June 25, 2013.January 5, 2017. Under thethis interest rate swap agreement, our Operating Partnership will pay a fixed interest rate of 3.12%1.63% to the issuing lender on the notional principal amount outstanding, effectively fixing the LIBOR portion of the interest rate at 3.12%. In return,and the issuing lender will pay to our Operating Partnership a floating rate, namely LIBOR, on the same notional principal amount. ThisThe interest rate swap agreement replacedhas been designated as a cash flow hedge.

As of September 27, 2014, our Operating Partnership had standby letters of credit issued under the previous interest rate swap agreement which terminated on March 31, 2010.

The Revolving Credit Facility in the aggregate amount of $44.9 million which expire periodically through April 3, 2015. Therefore, as of September 27, 2014, after giving effect to $100.0 million in outstanding borrowings, we had available borrowing capacity of $255.1 million under the Revolving Credit Facility.

The Amended Credit Agreement and the 2020 Senior Notes both contain various restrictive and affirmative covenants applicable to the Operating Partnership and the Partnership, respectively, including (i) restrictions on the incurrence of additional indebtedness, and (ii) restrictions on certain liens, investments, guarantees, loans, advances, payments, mergers, consolidations, distributions, sales of assets and other transactions. The RevolvingUnder the Amended Credit Facility contains certain financial covenants (a) requiringAgreement and the consolidated interest coverage ratio, as defined, atindentures governing the Partnership level to be not less than 2.5 to 1.0 as of the end of any fiscal quarter; (b) prohibiting the total consolidated leverage ratio, as defined, at the Partnership level from being greater than 4.5 to 1.0 as of the end of any fiscal quarter; and (c) prohibiting the senior secured consolidated leverage ratio, as defined, ofSenior Notes, the Operating Partnership from being greater than 3.0 to 1.0 as ofand the end of any fiscal quarter. Under the 2020 Senior Note indenture, wePartnership are generally permitted to make cash distributions equal to available cash, as defined, as of the end of the immediately preceding quarter, if no event of default exists or would exist upon making such distributions, and with respect to the Partnership’sindentures 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 2020 Senior Notes and the RevolvingAmended Credit FacilityAgreement as of September 24, 2011.

27, 2014.

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 2014, we recognized charges of $5.3 million to write-off unamortized debt origination costs associated with the tender offer and redemption of our 2018 Senior Notes. 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. Other assets at September 27, 2014 and September 28, 2013 include debt origination costs with a net carrying amount of $21.0 million and $21.3 million, respectively.

The aggregate amounts of long-term debt maturities subsequent to September 27, 2014 are as follows: fiscal 2015 through fiscal 2016: $-0-; fiscal 2017: $100.0 million; fiscal 2018: $-0-; fiscal 2019: $-0-; and thereafter: $1,121.2 million.

Partnership Distributions

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

On October 20, 2011,23, 2014, we announced that our Board of Supervisors had declared a quarterly distribution of $0.8525$0.8750 per Common Unit or $3.41 onfor the three months ended September 27, 2014. This quarterly distribution rate equates to an annualized basis, in respectrate of the fourth quarter of fiscal 2011 payable$3.50 per Common Unit. The distribution was paid on November 8, 201110, 2014 to holdersCommon Unitholders of record onas of November 1, 2011.

3, 2014.

41


Pension Plan Assets and Obligations

We have a noncontributory defined benefit pension plan which was originally designed to cover all of our eligible employees 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 2011, 20102014, 2013 or 2009.2012. As of September 24, 201127, 2014 and September 25, 201028, 2013 the plan’s projected benefit obligation exceeded the fair value of plan assets by $26.2$32.1 million and $17.7$27.9 million, respectively. As a result, the funded status ofnet liability recognized in the consolidated financial statements for the defined benefit pension plan declined $8.5increased by $4.2 million during fiscal 2011,2014, which was primarily attributable to an increase in the present value of the benefit obligation due to a general decrease in market interest rates, partially offset by a positive return on plan assets during fiscal 2011. The funded status of pension and other postretirement benefit plans are recognized as an asset or liability on our balance sheets and the changes in the funded status are recognized in comprehensive income (loss) in the year the changes occur.

rates.

Our investment policies and strategies, as set forth in the Investment Management Policy and Guidelines, are monitored by a Benefits Committee comprised of five members of management. 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 recent fiscal 2011 and fiscal 2010,years, significant declines in interest rates relevant to our benefit obligations, and/or poor performance in the broader capital markets in which our plan assets are invested, could have an adverse impact on the funded status of the defined benefit pension plan. For purposes of measuring the projected benefit obligation as of September 24, 201127, 2014 and September 25, 2010,28, 2013, we used a discount rate of 4.375%3.875% and 4.75%4.375%, respectively, reflecting current market rates for debt obligations of a similar duration to our pension obligations.

During fiscal 2010, lump sum settlement payments of $7.9 million exceeded the interest cost component of the net periodic pension cost. As a result, we recorded a non-cash settlement charge of $2.8 million during the fourth quarter of2014, fiscal 2010 in order to accelerate recognition of a portion of cumulative unrecognized losses in the defined benefit pension plan. These unrecognized losses were previously accumulated as a reduction to partners’ capital and were being amortized to expense as part of our net periodic pension cost. During fiscal 20112013 and fiscal 2009,2012, the amount of the pension benefit obligation settled through lump sum payments did not exceed the settlement threshold;threshold (combined service and interest costs of net periodic pension cost); therefore, a settlement charge was not required to be recognized forin any of those fiscal 2011 or fiscal 2009. Additional pension settlement charges may be required in future periods depending on the level of lump sum benefit payments made in future periods.

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.

42


Long-Term Debt Obligations and Operating Lease Obligations

Contractual Obligations

The following table summarizes payments due under our known contractual obligations as of September 24, 2011.

                         
                      Fiscal 
  Fiscal  Fiscal  Fiscal  Fiscal  Fiscal  2017 and 
(Dollars in thousands) 2012  2013  2014  2015  2016  thereafter 
                         
Long-term debt obligations $  $100,000  $  $  $  $250,000 
Interest payments  25,033   25,033   18,438   18,438   18,438   64,531 
Operating lease obligations (a)  15,836   13,346   11,540   8,480   4,993   4,709 
Self-insurance obligations (b)  13,188   10,706   8,212   4,900   3,110   12,724 
Other contractual obligations (c)  7,870   4,949   2,431   1,777   2,255   18,783 
                   
Total $61,927  $154,034  $40,621  $33,595  $28,796  $350,747 
                   
27, 2014:

(Dollars in thousands)  Fiscal
2015
   Fiscal
2016
   Fiscal
2017
   Fiscal
2018
   Fiscal
2019
   Fiscal
2020 and
thereafter
 

Long-term debt obligations

  $—      $—      $100,000    $—      $—      $1,121,180  

Interest payments

   77,999     77,999     75,493     72,843     72,843     204,655  

Operating lease obligations (a)

   25,266     17,781     12,199     9,224     6,131     7,469  

Self-insurance obligations (b)

   14,356     12,236     9,232     5,374     3,369     17,883  

Other contractual obligations (c)

   4,308     4,156     4,054     2,201     1,282     16,592  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

  $121,929    $112,172    $200,978    $89,642    $83,625    $1,367,779  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

(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 amountsamount to $4.2$3.9 million, $3.5 million, $2.7 million, $1.3$1.5 million, $0.9 million and $4.9$5.8 million for each of the next five fiscal years and thereafter, respectively, and are included in other assets on the consolidated balance sheet.
(c)These amounts are included in our consolidated balance sheet and primarily include payments for postretirement and long-term incentive benefits as well as periodic settlements of our interest rate swap agreement.benefits.

Additionally, we have standby letters of credit in the aggregate amount of $54.9$44.9 million, in support of retention levels under our casualty insurance programs and certain lease obligations, which expire periodically through April 15, 2012.

3, 2015.

Operating Leases

We lease certain property, plant and equipment for various periods under noncancelable operating leases, including 63%47% of our vehicle fleet, approximately 34%27% of our customer service centers and portions of our information systems equipment. Rental expense under operating leases was $18.9$31.8 million, $17.6$33.0 million and $17.3$23.6 million for fiscal 2011, 20102014, 2013 and 2009,2012, respectively. Future minimum rental commitments under noncancelable operating lease agreements as of September 24, 201127, 2014 are presented in the table above.

43


Off-Balance Sheet Arrangements

Guarantees

Certain of our operating leases, primarily those for transportation equipment with remaining lease periods scheduled to expire periodically through fiscal 2018,2021, 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, iswas approximately $9.7$14.1 million. The fair value of residual value guarantees for outstanding operating leases was de minimis as of September 24, 201127, 2014 and September 25, 2010.

28, 2013.

Recently Issued Accounting Pronouncements

Pronouncements.

In May 2011,2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09 “Revenue from Contracts with Customers” (“ASU 2014-09”). This update provides a principles-based approach to revenue recognition, requiring revenue recognition to depict the transfer of goods or services to customers in an accountingamount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The ASU provides a five-step model to be applied to all contracts with customers. The five steps are to identify the contract(s) with the customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract and recognize revenue when each performance obligation is satisfied. The revenue standard update to provide guidance on achieving a consistent definition of and common requirements for fair value measurement and related disclosure requirements in US GAAP. The new guidance requires quantitative information about unobservable inputs, valuation processes and sensitivity analysis associated with fair value measurements categorized within Level 3 of the fair value hierarchy, and is effective prospectively duringfor the first interim andperiod within annual reporting periods beginning after December 15, 2011,2016, which will be the secondour first quarter of our 2012 fiscal year. Earlyyear 2018. ASU 2014-09 can be applied either retrospectively to each prior reporting period presented or retrospectively with the cumulative effect of initially applying the update recognized at the date of the initial application along with additional disclosures. We are evaluating the impacts, if any, the adoption is not permitted. No material impact is expectedof ASU 2014-09 will have on our consolidatedresults of operations, financial position or cash flows.

Recently Adopted Accounting Pronouncements.

In December 2011, the FASB issued an 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 amendment, further clarified with ASU 2013-01, enhances 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. We adopted ASU 2011-11 and ASU 2013-01 on September 29, 2013 and included further disclosure regarding offsetting assets and liabilities for derivative instruments accounted for under ASC 815. As this guidance affects disclosures only, its adoption had no impact on our financial position, results of operations andor cash flows.

In June 2011,February 2013, the FASB issued an accounting standard updateASU to provide guidance on increasingestablish the prominence of items reported in other comprehensive income. This update eliminateseffective date for the optionrequirement to present components of reclassifications out of accumulated other comprehensive income as parteither parenthetically on the face of the statement of partners’ capital and requires that the total of comprehensive income, the components of net income and the components of other comprehensive income be presented either in a single continuous statement of comprehensive incomefinancial statements or in two separate but consecutive statements. Earlythe notes to the financial statements (“ASU 2013-02”). We adopted ASU 2013-02 on September 29, 2013 and its adoption of this updated guidance is permitted, and it becomes effective retrospectively during interim and annual periods beginning after December 15, 2011, which will be the second quarter of our 2012 fiscal year. This update doesdid not change the items that must be reported in other comprehensive income.

In September 2011, the FASB issued a revised accounting standard allowing companies to first assess qualitative factors to determine whetherincome, nor did it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If, as a result of the qualitative assessment, it is more likely than not that the fair value of a reporting unit is less than its carrying amount, a more detailed two-step goodwill impairment test would be performed to identify a potential goodwill impairment and measure the amount of loss to be recognized, if any. The standard will be effective for annual and interim goodwill impairment tests performed after December 31, 2011, with early adoption permitted. The adoption of this standard is not expected tohave an impact the Partnership’son our financial position, results of operations or cash flows.

ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

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

44


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 optionoptions contracts and, in certain instances, over-the-counter optionoptions 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.

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 and option contracts are generally settled at the expiration of the contract term either by physical delivery, orand swap and options contracts are generally settled at expiration through a net settlement mechanism. Market risks associated with futures, options and forward contractsour 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 optionoptions 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 propane optionoptions 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 plus1/2 of 1% or the agent bank’s prime rate, or LIBOR plus 1%, plus the applicable margin. The applicable margin is dependent on the level of the Partnership’s total consolidated leverage ratio (the total ratio of consolidated total debt to consolidated EBITDA). Therefore, we are subject to interest rate risk on the variable component of the interest rate. We manage our interest rate risk by entering into interest rate swap agreements. The interest rate swaps have been designated as a cash flow hedge. Changes in the fair value of the interest rate swaps are recognized in other comprehensive income (“OCI”) until the hedged item is recognized in earnings. At September 24, 2011,27, 2014, the fair value of the interest rate swaps was $4.6a net liability of $1.5 million, representing an unrealized loss andwhich is included within other current liabilities and other liabilities, as applicable, with a corresponding debitunrealized loss reflected in OCI.

accumulated other comprehensive income.

45


Derivative Instruments and Hedging Activities

All of our derivative instruments are reported on the balance sheet at their fair values. On the date that futures, forward and option contractsderivative 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:

 A.The fair value of open positions as of September 24, 2011.27, 2014.

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

Based on the sensitivity analysis described above, the hypothetical 10% adverse change in market prices for open futures and option contractsderivative instruments as of September 24, 201127, 2014 indicates a reductionan increase in potential future net gainslosses of $1.1 million as of September 24, 2011.$2.7 million. 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.

46


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  Year 
Fiscal 2011
                    
Revenues $328,307  $464,102  $216,563  $181,580  $1,190,552 
Cost of products sold  186,504   259,832   125,175   107,208   678,719 
Severance charges     2,000         2,000 
Operating income (loss)  50,341   107,233   353   (14,699)  143,228 
Net income (loss)  43,129   100,316   (6,787)  (21,692)  114,966 
Net income (loss) per common unit — basic (b)  1.22   2.82   (0.19)  (0.61)  3.24 
Net income (loss) per common unit — diluted (b)  1.21   2.81   (0.19)  (0.61)  3.22 
                     
Cash provided by (used in)                    
Operating activities  (4,858)  54,696   60,003   22,945   132,786 
Investing activities  (6,390)  (3,194)  (5,285)  (4,636)  (19,505)
Financing activities  (30,062)  (30,177)  (30,194)  (30,203)  (120,636)
EBITDA (c) $58,521  $115,687  $10,023  $(5,375) $178,856 
Adjusted EBITDA (c) $60,094  $113,564  $10,336  $(4,569) $179,425 
Retail gallons sold                    
Propane  86,286   114,034   54,629   43,953   298,902 
Fuel oil and refined fuels  11,393   16,249   5,621   3,978   37,241 
                     
Fiscal 2010
                    
Revenues $301,432  $469,163  $198,070  $168,029  $1,136,694 
Cost of products sold  150,366   248,459   106,627   92,999   598,451 
Pension settlement charge           2,818   2,818 
Operating income (loss)  55,757   114,797   555   (17,741)  153,368 
Loss on debt extinguishment (a)     9,473         9,473 
Net income (loss)  48,375   98,388   (6,616)  (24,831)  115,316 
Net income (loss) per common unit — basic (b)  1.37   2.78   (0.19)  (0.70)  3.26 
Net income (loss) per common unit — diluted (b)  1.36   2.76   (0.19)  (0.70)  3.24 
                     
Cash provided by (used in)                    
Operating activities  (14,726)  72,057   72,393   26,073   155,797 
Investing activities  (3,663)  (3,487)  (13,614)  (9,347)  (30,111)
Financing activities  (29,288)  (43,154)  (29,665)  (29,844)  (131,951)
EBITDA (c) $62,841  $112,466  $9,423  $(10,001) $174,729 
Adjusted EBITDA (c) $66,249  $123,671  $9,142  $(6,642) $192,420 
Retail gallons sold                    
Propane  89,981   124,457   56,037   47,431   317,906 
Fuel oil and refined fuels  13,056   18,381   6,631   5,128   43,196 

   First
Quarter
  Second
Quarter
  Third
Quarter
  Fourth
Quarter
  Total
Year
 

Fiscal 2014

      

Revenues

  $526,056   $873,772   $297,143   $241,286   $1,938,257  

Cost of products sold

   280,526    517,198    161,482    121,544    1,080,750  

Operating income (loss)

   80,055    171,044    (26,575  (34,398  190,126  

Loss on debt extinguishment (a)

   —      —      11,589    —      11,589  

Net income (loss)

   58,671    149,547    (58,989  (54,720  94,509  

Net income (loss) per common unit—basic (b)

   0.97    2.47    (0.98  (0.90  1.56  

Net income (loss) per common unit—diluted (b)

   0.97    2.46    (0.98  (0.90  1.56  

Cash provided by (used in):

      

Operating activities

   4,161    16,226    124,583    80,581    225,551  

Investing activities

   (3,424  (4,947  (3,731  (4,430  (16,532

Financing activities

   (52,702  2,232    (120,313  (52,829  (223,612

EBITDA (c)

  $114,882   $204,326   $(5,172 $900   $314,936  

Adjusted EBITDA (c)

  $117,708   $206,269   $10,023   $4,502   $338,502  

Retail gallons sold

      

Propane

   157,858    213,689    83,156    76,040    530,743  

Fuel oil and refined fuels

   13,997    22,617    6,981    5,476    49,071  

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 (a)

   —      —      —      2,144    2,144  

Net income (loss)

   57,620    129,484    (45,187  (63,119  78,798  

Net income (loss) per common unit—basic (b)

   1.05    2.29    (0.77  (1.05  1.35  

Net income (loss) per common unit—diluted (b)

   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 (c)

  $112,835   $185,293   $10,850   $(3,762 $305,216  

Adjusted EBITDA (c)

  $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  

(a)During the secondthird quarter of fiscal 20102014, we completedrepurchased and satisfied and discharged all of our 2018 Senior Notes with net proceeds from the issuance of $250.0 million of 7.375% senior notes maturing in March 2020the 2024 Senior Notes and cash on hand pursuant to replace the previously existing 6.875% senior notes that were set to mature in December 2013.a tender offer and redemption. In connection with the refinancing,this tender offer and redemption, we recognized a loss on debtthe extinguishment of $9.5debt of $11.6 million consisting of $7.2$31.6 million for the redemption premium and related fees, as well as the write-off of $5.3 million and ($25.3) million in unamortized debt origination costs and unamortized premium, respectively. 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 $2.2$2.1 million and ($11.7) million in unamortized debt origination costs and unamortized discount.premium, respectively.

47


(b)Basic net income (loss) per Common Unit is computed by dividing net income (loss) by the weighted average number of outstanding Common Units, and restricted units granted under the restricted unit plansRestricted 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.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 plansRestricted 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.
(c)EBITDA represents net income before deducting interest expense, income taxes, depreciation and amortization. Adjusted EBITDA represents EBITDA excluding the unrealized net gain or loss from mark-to-market activity for derivative instruments loss on debt extinguishment, pension settlement charge and severance charges.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. In addition, certain of our incentive compensation plans covering executives and other employees utilize Adjusted EBITDA as the performance target. Moreover, our revolving credit agreement requires us to use Adjusted EBITDA as a component in calculating our leverage and interest coverage ratios. EBITDA and Adjusted EBITDA are not recognized terms under US GAAP and should not be considered as an alternative to net income or net cash provided by operating activities determined in accordance with US GAAP. Because EBITDA and Adjusted EBITDA as determined by us excludes some, but not all, items that affect net income, they may not be comparable to EBITDA and Adjusted EBITDA or similarly titled measures used by other companies. The following table sets forth (i) our calculations of EBITDA and (ii) a reconciliation of EBITDA, as so calculated, to our net cash provided by (used in) provided by operating activities (amounts in thousands):

Fiscal 2014

  First
Quarter
  Second
Quarter
  Third
Quarter
  Fourth
Quarter
  Total
Year
 

Net income (loss)

  $58,671   $149,547   $(58,989 $(54,720 $94,509  

Add:

      

Provision for income taxes

   177    271    163    156    767  

Interest expense, net

   21,207    21,226    20,662    20,166    83,261  

Depreciation and amortization

   34,827    33,282    32,992    35,298    136,399  
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

EBITDA

   114,882    204,326    (5,172  900    314,936  

Unrealized (non-cash) losses (gains) on changes in fair value of derivatives

   290    (291  (707  402    (306

Integration related costs

   2,536    2,234    4,313    3,200    12,283  

Loss on debt extinguishment

   —      —      11,589    —      11,589  
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Adjusted EBITDA

   117,708    206,269    10,023    4,502    338,502  

Add (subtract):

      

Provision for income taxes

   (177  (271  (163  (156  (767

Interest expense, net

   (21,207  (21,226  (20,662  (20,166  (83,261

Unrealized (non-cash) (losses) gains on changes in fair value of derivatives

   (290  291    707    (402  306  

Integration related costs

   (2,536  (2,234  (4,313  (3,200  (12,283

Compensation cost recognized under Restricted Unit Plans

   1,638    1,951    2,074    1,727    7,390  

(Gain) loss on disposal of property, plant and equipment, net

   (237  (282  179    (181  (521

Changes in working capital and other assets and liabilities

   (90,738  (168,272  136,738    98,457    (23,815
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Net cash provided by operating activities

  $4,161   $16,226   $124,583   $80,581   $225,551  
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Fiscal 2013

  First
Quarter
  Second
Quarter
  Third
Quarter
  Fourth
Quarter
  Total
Year
 

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  

Loss on debt extinguishment

   —      —      —      2,144    2,144  

Multi-employer pension plan withdrawal charge

   —      —      6,000    1,000    7,000  
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

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  
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

 

48


                     
  First  Second  Third  Fourth  Total 
Fiscal 2011 Quarter  Quarter  Quarter  Quarter  Year 
Net income (loss) $43,129  $100,316  $(6,787) $(21,692) $114,966 
Add:                    
Provision for income taxes  366   98   273   147   884 
Interest expense, net  6,846   6,819   6,867   6,846   27,378 
Depreciation and amortization  8,180   8,454   9,670   9,324   35,628 
                
EBITDA  58,521   115,687   10,023   (5,375)  178,856 
Unrealized (non-cash) losses (gains) on changes in fair value of derivatives  1,573   (4,123)  313   806   (1,431)
Severance charges     2,000         2,000 
                
Adjusted EBITDA  60,094   113,564   10,336   (4,569)  179,425 
Add (subtract):                    
Provision for income taxes  (366)  (98)  (273)  (147)  (884)
Interest expense, net  (6,846)  (6,819)  (6,867)  (6,846)  (27,378)
Unrealized (non-cash) (losses) gains on changes in fair value of derivatives  (1,573)  4,123   (313)  (806)  1,431 
Severance charges     (2,000)        (2,000)
Compensation cost recognized under Restricted Unit Plans  1,332   1,067   737   786   3,922 
(Gain) loss on disposal of property, plant and equipment, net  (299)  (2,612)  67   72   (2,772)
Changes in working capital and other assets and liabilities  (57,200)  (52,529)  56,316   34,455   (18,958)
                
                     
Net cash (used in) provided by operating activities $(4,858) $54,696  $60,003  $22,945  $132,786 
                
                     
  First  Second  Third  Fourth  Total 
Fiscal 2010 Quarter  Quarter  Quarter  Quarter  Year 
Net income (loss) $48,375  $98,388  $(6,616) $(24,831) $115,316 
Add:                    
Provision for income taxes  199   328   363   292   1,182 
Interest expense, net  7,183   6,608   6,808   6,798   27,397 
Depreciation and amortization  7,084   7,142   8,868   7,740   30,834 
                
EBITDA  62,841   112,466   9,423   (10,001)  174,729 
Unrealized (non-cash) losses (gains) on changes in fair value of derivatives  3,408   1,732   (281)  541   5,400 
Loss on debt extinguishment     9,473         9,473 
Pension settlement charge           2,818   2,818 
                
Adjusted EBITDA  66,249   123,671   9,142   (6,642)  192,420 
Add (subtract):                    
Provision for income taxes  (199)  (328)  (363)  (292)  (1,182)
Interest expense, net  (7,183)  (6,608)  (6,808)  (6,798)  (27,397)
Unrealized (non-cash) (losses) gains on changes in fair value of derivatives  (3,408)  (1,732)  281   (541)  (5,400)
Compensation cost recognized under Restricted Unit Plans  992   1,025   1,136   852   4,005 
(Gain) loss on disposal of property, plant and equipment, net  (427)  293   283   (111)  38 
Changes in working capital and other assets and liabilities  (70,750)  (44,264)  68,722   39,605   (6,687)
                
                     
Net cash (used in) provided by operating activities $(14,726) $72,057  $72,393  $26,073  $155,797 
                

49


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

None.

ITEM 9A.
CONTROLS AND PROCEDURES
DISCLOSURE CONTROLS AND PROCEDURES.

Evaluation of Disclosure Controls and Procedures

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

Before filing this Annual Report, the Partnership completed an evaluation under the supervision and with the participation of the Partnership’s management, including the Partnership’s principal executive officer and principal financial officer, of the effectiveness of the design and operation of the Partnership’s disclosure controls and procedures as of September 24, 2011.27, 2014. Based on this evaluation, the Partnership’s principal executive officer and principal financial officer concluded that the Partnership’s disclosure controls and procedures were effective at the reasonable assurance level as of September 24, 2011.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING. 27, 2014.

Changes in Internal Control Over Financial Reporting

There have not been any changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) during the quarter ended September 24, 2011,27, 2014, 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’s Report on Internal Control Over Financial Reporting

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

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

The Partnership’s management has assessed the effectiveness of the Partnership’s internal control over financial reporting as of September 24, 2011.27, 2014. In making this assessment, the Partnership used the criteria established by the Committee of Sponsoring Organizations of the Treadway Commission (COSO)(“COSO”) in “Internal Control-Integrated Framework.Framework (1992).” These criteria are in the areas of control environment, risk assessment, control activities, information and communication, and monitoring. The Partnership’s assessment included documenting, evaluating and testing the design and operating effectiveness of its internal control over financial reporting.

Based on the Partnership’s assessment, as described above, management has concluded that, as of September 24, 2011,27, 2014, the Partnership’s internal control over financial reporting was effective.

Our independent registered public accounting firm, PricewaterhouseCoopers LLP, issued an attestation report dated November 23, 201126, 2014 on the effectiveness of our internal control over financial reporting, which is included herein.

 

50


ITEM 9B.
OTHER INFORMATION

None.

PART III

ITEM 10.
DIRECTORS, AND EXECUTIVE OFFICERS OF THE REGISTRANT
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. There are currently six Supervisors, who serve on the Board of Supervisors pursuant to the terms of the Partnership Agreement. Under the current Partnership Agreement, allmembers of our Board of Supervisors are elected by the Unitholders for three-year terms. All six current SupervisorsMessrs. Harold R. Logan, Jr., John D. Collins, Dudley C. Mecum, John Hoyt Stookey and Ms. Jane Swift were elected to their current three-year terms at the Tri-Annual Meeting heldof our Unitholders convened on July 22, 2009.

FiveMay 1, 2012 and then reconvened on May 14, 2012.

At its regular meeting on November 13, 2012, our Board of Supervisors, who are not officers or employeespursuant 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 or its subsidiaries, serveAgreement, 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 its meeting on November 12, 2014, and upon the recommendation of its Nominating/Governance Committee, our Board of Supervisors elected Michael A. Stivala, our current President and Chief Executive Officer, to fill the vacancy on the Board created by the retirement from the Board of Michael J. Dunn, Jr. effective on September 27, 2014, concurrently with Mr. Dunn’s retirement as our Chief Executive Officer. Mr. Stivala was elected for a term due to expire at the next Tri-Annual Meeting of our Unitholders, currently scheduled for Spring 2015.

The Audit Committee withof our Board of Supervisors has the authority to review, at the request of the Board of Supervisors, specific matters as to which the Board of Supervisors believes there may be a conflict of interest, or which may be required to be disclosed pursuant to Item 404(a) of Regulation S-K adopted by the Securities and Exchange Commission,SEC, in order to determine if the resolution or course of action in respect of such conflict proposed by the Board of Supervisors is fair and reasonable to us. Under the Partnership Agreement, any matter that receives the “Special Approval” of the Audit Committee (i.e., approval by a majority of the members of the Audit Committee) is conclusively deemed to be fair and reasonable to us, is deemed approved by all of our partners and shall not constitute a breach of the Partnership Agreement or any duty stated or implied by law or equity as long as the material facts known to the party having the potential conflict of interest regarding that matter were disclosed to the Audit Committee at the time it gave Special Approval. The Audit Committee also assists the Board of Supervisors in fulfilling its oversight responsibilities relating to (a)(i) integrity of the Partnership’s financial statements and internal control over financial reporting; (b)(ii) the Partnership’s compliance with applicable laws, regulations and its code of conduct; (c)(iii) independence and qualifications of the independent registered public accounting firm; (d)(iv) performance of the internal audit function and the independent registered public accounting firm; and (e)(v) accounting complaints.

The

Until July 22, 2014, the Audit Committee consisted of all seven of our non-employee Supervisors (namely, Messrs. Logan, Stookey, Mecum, Collins, Caldwell, Chanin and Ms. Swift), all of whom had been determined by our Board of Supervisors has determined that all five members of the Audit Committee, Harold R. Logan, Jr., John Hoyt Stookey, Dudley C. Mecum, John D. Collins and Jane Swift areto be 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. At its meeting on July 22, 2014, the Board reduced the size of the Audit Committee to four—Messrs. Caldwell, Collins, Mecum and Ms. Swift—and reaffirmed the above determinations with respect to those four members.

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 regular meetings of the Audit Committee.Board of Supervisors. Investors and other parties interested in communicating directly with the non-management Supervisors as a group may do so by writing to the Non-Management Members of the Board of Supervisors, c/o Company Secretary, Suburban Propane Partners, L.P., P.O. Box 206, Whippany, New Jersey 07981-0206.

07981-0206

51


Board of Supervisors and Executive Officers of the Partnership

The following table sets forth certain information with respect to the members of the Board of Supervisors and our executive officers as of November 23, 2011.26, 2014. Officers are appointed by the Board of Supervisors forone-year terms and Supervisors are elected by the Unitholders forthree-year terms.

Name

  Age   

Position With the Partnership

Michael J. Dunn, Jr.A. Stivala

   6245    President and Chief Executive Officer; Member of the Board of Supervisors
Michael A. Stivala

Mark Wienberg

   4252Chief Operating Officer

Michael A. Kuglin

44    Chief Financial Officer & Chief Accounting Officer
Michael M. Keating

Paul Abel

   5861    Senior Vice President — Administration
A. Davin D’Ambrosio47Vice President and Treasurer
Paul Abel58Vice President, General Counsel and Secretary
Mark Anton, II

Steven C. Boyd

   5450    Senior Vice President — Business DevelopmentPresident—Field Operations
Steven C. Boyd

Douglas T. Brinkworth

   4753    Senior Vice President — Field OperationsPresident—Product Supply, Purchasing & Logistics
Douglas T. Brinkworth

Michael M. Keating

61Senior Vice President

Neil E. Scanlon

49Senior Vice President—Information Services

A. Davin D’Ambrosio

   50    Vice President — Product Supplyand Treasurer
Neil Scanlon

Sandra N. Zwickel

   4648    Vice President — Information ServicesPresident—Human Resources
Mark Wienberg49Vice President — Operational Support and Analysis
Michael Kuglin

Daniel S. Bloomstein

   41    Vice President and Chief Accounting OfficerController

Harold R. Logan, Jr.

   6770    Member of the Board of Supervisors (Chairman)

John Hoyt Stookey

   8184    Member of the Board of Supervisors (Chairman of the Compensation Committee)

Dudley C. Mecum

   7679    Member of the Board of Supervisors

John D. Collins

   7376    Member of the Board of Supervisors (Chairman of the Audit Committee)

Jane Swift

   4649Member of the Board of Supervisors

Lawrence C. Caldwell

68Member of the Board of Supervisors

Matthew J. Chanin

60    Member of the Board of Supervisors

Mr. DunnStivala has served as our President since May 2005April 2014 and as our Chief Executive Officer since September 2009. From June 1998 until May 2005 he was Senior Vice President, becoming Senior Vice President — Corporate Development in November 2002.2014. Mr. DunnStivala has served as a Supervisor since July 1998. HeNovember 2014. From November 2009 until March 2014 he was Vice President — Procurement and Logistics from March 1997 until June 1998. Before joining the Partnership, Mr. Dunn was Vice President of Commodity Trading for the investment banking firm of Goldman Sachs & Company (“Goldman Sachs”). Mr. Dunn is the sole member of the General Partner.

Mr. Dunn’s qualifications to sit on our Board include his more than 14 years of experience in the propane industry, including as our President for the past 6 years and Chief Executive Officer for the past 2 years, which day to day leadership roles have provided him with intimate knowledge of our operations.
Mr. Stivala has served as Chief Financial Officer, since November 2009, and, before that, 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 memberStivala’s qualifications to sit on our Board include his thirteen years of the American Institute of Certified Public Accountants.

Mr. Keating has served as Senior Vice President — Administration since July 2009. From July 1996 to that date he was Vice President — Human Resources and Administration. He previously held senior human resource positions at Hanson Industries (the United States management division of Hanson plc, a global diversified industrial conglomerate) and Quantum Chemical Corporation (“Quantum”), a predecessor of the Partnership.
Mr. D’Ambrosio has served as Treasurer since November 2002 and was additionally made a Vice President in October 2007. He served as Assistant Treasurer from October 2000 to November 2002 and as Director of Treasury Services from January 1998 to October 2000. Mr. D’Ambrosio joined the Partnership in May 1996 after ten yearsexperience in the commercial banking industry.
Mr. Abel has servedpropane industry, including as General Counselour current President and Secretary since June 2006Chief Executive Officer and, was additionally made a Vice President in October 2007. From May 2005 until June 2006, Mr. Abel was Assistant General Counselbefore that, as our Chief Financial Officer for almost 7 years, which day to day leadership roles have provided him with intimate knowledge 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.

our operations.

52


Mr. Anton has served as Vice President — Business Development since he joined the Partnership in 1999. Prior to joining the Partnership, Mr. Anton worked as an Area Manager for another large multi-state propane marketer and was a Vice President at several large investment banking organizations.
Mr. Boyd has served as Vice President — Field Operations (formerly Vice President — Operations) since October 2008. Prior to that he was Southeast and Western Area Vice President since March 2007, Managing Director — Area Operations since November 2003 and Regional Manager — Northern California since May 1997. Mr. Boyd held various managerial positions with predecessors of the Partnership from 1986 through 1996.
Mr. Brinkworth has served as Vice President — Product Supply (formerly Vice President — Supply) since May 2005. Mr. Brinkworth joined the Partnership in April 1997 after a nine year career with Goldman Sachs and, since joining the Partnership, has served in various positions in the product supply area.
Mr. Scanlon became Vice President — Information Services in November 2008. Prior to that he served as Assistant Vice President — Information Services since November 2007, Managing Director — Information Services from November 2002 to November 2007 and Director — Information Services from April 1997 until November 2002. Prior to joining the Partnership, Mr. Scanlon spent several years with JP Morgan & Co., most recently as Vice President — Corporate Systems and earlier held several positions with Andersen Consulting (“Accenture”), an international systems consulting firm, most recently as Manager.
Mr. Wienberg has served as our Chief Operating Officer since April 2014 and before that was our Vice President — President—Operational Support and Analysis (formerly Vice President — 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 — President—Finance of International Home Foods Corp., a consumer products manufacturer.

Mr. Kuglin has served as our Chief Financial Officer & Chief Accounting Officer since September 2014 and was our Vice President—Finance and Chief Accounting Officer from April 2014 through September 2014. Prior to that he served as our Vice President and Chief Accounting Officer since November 2011. Prior to that he was2011, our Controller and Chief Accounting Officer since November 2009 and our 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. Abel has served as our General Counsel and Secretary since June 2006, was additionally made a Vice President in October 2007 and a Senior Vice President in April 2014. Prior to joining the Partnership, Mr. Abel served as senior in-house legal counsel (including as a General Counsel) for several technology companies.

Mr. Boyd has served as our Senior Vice President—Field Operations since April 2014; previously he was 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 Senior Vice President—Product Supply, Purchasing & Logistics since April 2014 and was previously 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. Keating has served as our Senior Vice President since October 2014 and before that was 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. Scanlon became our Senior Vice President—Information Services in April 2014, after serving as our Vice President— Information Services since 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. 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.

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. Bloomstein joined the Partnership as its Controller in April 2014. For the ten years prior to joining the Partnership, he held several executive financial and accounting positions with The Access Group, a network of professional services companies, and with Dow Jones & Company, Inc., a global news and financial information company. Mr. Bloomstein started his career with the international accounting firm PricewaterhouseCoopers LLP, working his way to the level of Manager in the Assurance/Business Advisory Services practice. Mr. Bloomstein is a Certified Public Accountant and a member of the American Institute of Certified Public Accountants.

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

LLP.

Over the past 40forty 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.

53


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 forof a number of non-profit organizations, including founding and serving as non-executive Chairman of Per Scholas Inc. (a non-profit organization dedicated to using technologytraining inner city individuals to improve the lives of residents of the South Bronx)become computer and software technicians), The Berkshire Choral Festival and Landmark Volunteers (places high school students in volunteer positions with non-profit organizations during summer vacations) and has also servedserves on the Board of Directors of The Clark Foundation and The Robert Sterling Clark Foundation and The Berkshire Taconic Community Foundation.
as a Life Trustee of the Boston Symphony Orchestra.

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

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

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

companies, including, until 2007, Citigroup, Inc.

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

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

Ms. Swift has served as a Supervisor since April 2007. She is currently the CEO of Middlebury Interactive Languages, LLC, a marketer of world language products. From 2010 through July 2011, Ms. Swift served as Senior Vice President of President—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 The Young Writers Project, and currently serves on the boards of Sally Ride Science Inc. and several not-for-profit boards, including The Republican Majoritythe National Alliance for Choice and Landmark Volunteers, Inc.Public Charter Schools. Ms. Swift is also a Trustee for Champlain College. Prior to joining Arcadia, Ms. Swift served for 15fifteen 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 15fifteen years in state government.

54

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 to 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 eight years and Chief Financial Officer for six years. From 1985 to 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 automotive original equipment manufacturers 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 forty 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 2011.

year 2014.

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 atwww.suburbanpropane.com or upon written request directed to: Suburban Propane Partners, L.P., Investor Relations, P.O. Box 206, Whippany, New Jersey 07981-0206. Any amendments to, or waivers from, provisions of our Code of Ethics or our Code of Business Conduct that apply to our principal executive officer, principal financial officer and principal accounting officer will be posted on our website.

Corporate Governance Guidelines

We have adopted Corporate Governance Guidelines and PoliciesPrinciples in accordance with the NYSE corporate governance listing standards in effect as of the date of this Annual Report. In addition, we have adopted certain Corporate Governance Policies, including an Equity Holding Policy for Supervisors and Executives and an Incentive Compensation Recoupment Policy. A copy of our Corporate Governance Guidelines and Principles, as well as a copy of the Corporate Governance Policies, is available without charge from our website atwww.suburbanpropane.com or upon written request directed to: Suburban Propane Partners, L.P., Investor Relations, P.O. Box 206, Whippany, New Jersey 07981-0206.

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

Compensation Committee Charter

Five

Until July 22, 2014, all seven Supervisors who are not officers or employees of the Partnership or its subsidiaries serve(namely, Messrs. Logan, Stookey, Mecum, Collins, Caldwell, Chanin and Ms. Swift) served on the Compensation Committee. The Board of Supervisors had determined that all seven members of the Compensation Committee are independent. At its meeting on July 22, 2014, the Board reduced the size of the Compensation Committee to three – Messrs. Chanin, Logan and Stookey – and reaffirmed the above determination with respect to those three members.

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

During fiscal 2014, the Compensation Committee independently retained Towers Watson & Co. (“Towers Watson”), a human resources consulting firm, to assist the Compensation Committee in developing competitive compensation packages for those executive officers identified by the Compensation Committee as our senior core executive officers pursuant to a succession plan approved by the Board of Supervisors. See Item 11 below.

Nominating/Governance Committee Charter

We have adopted a written Nominating/Governance Committee Charter. A copy of our Nominating/Governance Committee Charter is available without charge from our website atwww.suburbanpropane.com or upon written request directed to: Suburban Propane Partners, L.P., Investor Relations, P.O. Box 206, Whippany, New Jersey 07981-0206.

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.Our Chief Executive Officer submits his Annual CEO Certification to the NYSE each December. In December 2013, our then Chief Executive Officer, Michael J. Dunn, Jr., submitted his Annual CEO Certification for our 2011 fiscal year to the NYSE without qualification.

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ITEM 11.
EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

This Compensation Discussion and Analysis explains our executive compensation philosophy, policies and practices with respect to the following executive officers of the Partnership, (theto whom we refer to as our “named executive officers”): Mr. Dunn, our former Chief Executive Officer (who held the position of President and Chief Executive Officer until March 31, 2014, and the position of Chief Executive Officer through September 27, 2014); Mr. Stivala, our current President and Chief Executive Officer (who held the position of Chief Financial Officer until March 31, 2014, and the position of President from April 1, 2014 through September 27, 2014); Mr. Kuglin, our current Chief Financial Officer and Chief Accounting Officer (who held the position of Vice President and Chief Accounting Officer until March 31, 2014, and the position of Vice President—Finance and Chief Accounting Officer, a position that required him to act in a manner identical to that of a Chief Financial Officer, from April 1, 2014 through September 27, 2014); and our three other three most highly compensated executive officers.

officers: Mr. Wienberg, our Chief Operating Officer; Mr. Boyd, our Senior Vice President—Field Operations; and Mr. Brinkworth, our Senior Vice President—Product Supply, Purchasing & Logistics.

In accordance with a management succession plan developed by the Compensation Committee of the Partnership’s Board of Supervisors, which we hereafter refer to as the “Committee,” in close collaboration with Mr. Dunn, Mr. Dunn retired at the conclusion of fiscal 2014.

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 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;

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.

Long-Term Incentive Plan awards; and

Awards of restricted units under the Restricted Unit Plan.

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

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

Providing our executive officers with an annual incentive target that encourages them to achieve or exceed targeted financial results and operating performance for the fiscal year;
Providing a long-term incentive plan that encourages our executive officers to implement activities and practices conducive to sustainable, profitable growth; and
Providing our executive officers with restricted units in order to retain the services of the participating executive officers over a five-year period while simultaneously encouraging behaviors conducive to the long-term appreciation of our Common Units.

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

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The November 13, 2013 Compensation Committee Meeting


Annually,As in past fiscal years, our Senior Vice President of President—Administration prepares(now Senior Vice President) prepared 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.2014. The Committee considersconsidered a number of factors in establishing the fiscal 2014 executive compensation packages, for each executive officer, including, but not limited to, tenure,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 is continually assessed by the Committee and by our highest-ranking executive officers and also factors into the decision-making process, particularly in relationyear to promotions and increases in base compensation.year. In addition, as part of the Committee’s annual review of each executive officer’s total compensation package, the Committee iswas provided with benchmarking data for comparison. TheThis benchmarking data is just one of a number of factors that was considered by the Committee, but iswas not necessarily the most persuasive factor.

The benchmarking data provided to the Committee for the 2011 fiscal year2014 was derived from the Mercer Human Resource Consulting, Inc. (“Mercer”) Benchmark Database containing information obtained from surveys of over 2,2693,035 organizations and approximately 2011,224 positions which may or may not include similarly-sized national propane marketers. The Committee does not base its benchmarking solely on a peer group of other propane marketers. The use of the Mercer database provides a broad base of compensation benchmarking information for companies of a size similar size to the Partnership. The benchmarking information used by

In making their decisions regarding executive compensation packages for fiscal 2014, for executive officers currently below the level of senior vice president, the members of the Committee consistedreviewed the total cash compensation opportunities that were provided to each member of organizations includedthis subset of our executive officers (none of whom are our named executive officers) during the previous completed fiscal year. “Total cash compensation opportunity” consists of base salary, an annual cash bonus, and Long-Term Incentive Plan awards. The Committee then compared these officers’ total cash compensation opportunities to the total mean cash compensation opportunities for parallel positions in the Mercer databasedatabase. By focusing on total cash compensation opportunity as a whole, instead of on single components of compensation such as base salary, when it met on November 13, 2013, the Committee created fiscal 2014 compensation packages for this subset of our executive officers that report median annual revenuesemphasized the performance-based components of between $1.4 billion and $3.8 billion per year.

compensation.

As in prior years, the Committee did not base its benchmarking solely on a peer group of other propane marketers. The Committee adopted this approach because it believes that using the Mercer database to evaluate “total cash compensation opportunities” is appropriate because of the proximity of the Partnership’sour 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.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.

Conversely,

In connection with succession planning, the Committee unanimously decided to engage the services of Towers Watson & Co. (“Towers Watson”), a human resources consulting firm, for assistance in developing competitive compensation packages for those executive officers identified by the reasons set forth underCommittee as our senior level executive officers (i.e., those executives who are currently at or above the subheading “2003 Long-Term Incentive Plan” below,level of senior vice president). The Committee agreed that it would defer making promotion-related decisions (with the notable exception of the promotion of Mr. Stivala discussed below) and compensation-related decisions relative to our senior core executive officers until its January 22, 2014 meeting, by which time it was contemplated that Towers Watson would have completed a study of the Partnership, the executive team, and our past compensation practices.

In response to Mr. Dunn’s having informed the committee that he intended to retire at the end of fiscal 2014, the Committee promoted Mr. Stivala to the position of President (effective April 1, 2014) at its November 13, 2013 meeting. For Mr. Stivala and for those whom the Committee identified as our senior level executive officers (currently our Chief Operating Officer, our Chief Financial Officer and Chief Accounting Officer, and our Senior Vice Presidents), the Committee decided to include other propane marketers, structured as publicly traded partnerships, inpostpone establishing fiscal 2014 compensation-related adjustments until after the peer group it selectedCommittee was presented with recommendations from Towers Watson.

The January 22, 2014 Compensation Committee Meeting

After completing a study of the Partnership and the responsibilities that had already been and were to be assumed by our senior level executive officers, a principal of Towers Watson provided the Committee with a presentation that included compensation recommendations for the 2003 Long-Term Incentive Plan. Earning a payment under the 2003 Long-Term Incentive Plan is dependent upon the performance (referred to in the plan document as “total return to unitholders”) of our Common Units relative to the unit performance of a peerthis group of eleven other master limited partnerships over a three-year measurement period.

executives. In making their decisions regarding executive compensation packages foraccordance with the comingrecommendations of Towers Watson, the Committee established fiscal year the members of the Committee review the total cash compensation opportunities that were provided to our executive officers during the just completed fiscal year. Each executive officer’s “total cash compensation opportunity” consists of base salary, an annual cash bonus, and 2003 Long-Term Incentive Plan awards. The Committee then compares each executive officer’s total cash compensation opportunity to the total mean cash compensation opportunity for the parallel position in the Mercer database. By focusing on each executive officer’s total cash compensation opportunity as a whole, instead of on single components of compensation such as base salary, when it met on November 9, 2010, the Committee created fiscal 20112014 compensation packages for our executive officersPresident (who is currently our President and Chief Executive Officer), our Chief Operating Officer, our Senior Vice Presidents, and our Vice President—Finance and Chief Accounting Officer (who is currently our Chief Financial Officer and Chief Accounting Officer). The compensation packages established at this meeting became effective on April 1, 2014, the effective date on which Mr. Stivala was promoted to the position of President, Mr. Kuglin was promoted to the position of Vice President—Finance and Chief Accounting Officer, Mr. Wienberg was promoted to Chief Operating Officer, Mr. Boyd was promoted to the position of Senior Vice President—Field Operations, and Mr. Brinkworth was promoted to the position of Senior Vice President—Product Supply, Purchasing & Logistics.

The July 22, 2014 Compensation Committee Meeting

Continuing its preparation for Mr. Dunn’s retirement at the conclusion of fiscal 2014, the Committee approved Mr. Stivala’s assumption of the role and title of Chief Executive Officer in addition to his role as President. Because of the April 1, 2014 adjustments to Mr. Stivala’s overall compensation, the Committee chose not to adjust Mr. Stivala’s compensation at this time. This promotion became effective on September 28, 2014.

In addition, the Committee approved the promotion of Mr. Kuglin to Chief Financial Officer and Chief Accounting Officer. This promotion became effective on September 28, 2014. In establishing Mr. Kuglin’s compensation for this position, the Committee relied on the same Towers Watson study discussed above.

***

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 emphasizedno major revisions of its practices are required; however, the performance-based components of compensation.

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 President—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.

Among other duties, the Committee has overall responsibility for:

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

 

57

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

The Partnership’sOur sole use of the Mercer database was to provide the Committee with benchmarking data. Therefore, prior to the November 13, 2013 Committee meeting, neither our President and Chief Executive Officer nor our Senior Vice President ofPresident— Administration met with representatives from Mercer. The information provided by Mercer was derived from a proprietary database maintained by Mercer and, as such, there was no formal consultancy role played by them. The

In preparation for its January 22, 2014 Committee believes that the Mercer benchmarking data, which is provided tomeeting, the Committee bydirected Mr. Dunn, Mr. Stivala, Mr. Kuglin, Mr. Wienberg, and our Senior Vice PresidentPresident—Administration to meet with principals of Administration, can be used byTowers Watson to discuss the Committee as an objective benchmarkthen current responsibilities of our senior level executives and their thoughts on which decisions relative tothe future responsibilities of these executives in light of the Committee’s succession planning efforts. It was from these interviews with our senior executive officers that the principals of Towers Watson developed their recommendations regarding compensation can be based. In the course of its deliberations, the Committee compares the objective data obtained from the Mercer database to the internal analyses prepared by our Senior Vice President of Administration.

Among other duties, the Committee has overall responsibility for:
Reviewing and approving compensation of our President and Chief Executive Officer, Chief Financial Officer and our other executive officers;
Reporting to the Board of Supervisors any and all decisions regarding compensation changes for our President and Chief Executive Officer, Chief Financial Officer and our other executive officers;
Evaluating and approving our annual cash bonus plan, long-term incentive plan, restricted unit plan, as well as all other executive compensation policies and programs;
Administering and interpreting the compensation plans that constitute each component of our executive officers’ compensation packages; and
Engaging consultants, when appropriate, to provide independent, third-party advice on executive officer-related compensation.
senior level executive team.

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 for the first six months of fiscal 2014 (i.e., October 2013 through March 2014). For this period, the base salaries and cash bonus targets of our named executive officers remained identical to those in effect for fiscal 2011 (as determined at2013.

   Base
Salary
  Cash
Bonus
Target
  Long-
Term
Incentive
 

Michael J. Dunn, Jr.

   40  40  20

Michael A. Stivala

   46  36  18

Michael A. Kuglin

   51  33  16

Mark Wienberg

   46  36  18

Steven C. Boyd

   46  36  18

Douglas T. Brinkworth

   46  36  18

The following table summarizes the Committee’s November 9, 2010 meeting)components as percentages of each named executive officer’s total cash compensation opportunity for the second six months of fiscal 2014 (i.e., April 2014 through September 2014).

             
      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%

   Base
Salary
  Cash
Bonus
Target
  Long-
Term
Incentive
 

Michael J. Dunn, Jr.

   40  40  20

Michael A. Stivala

   44  44  12

Michael A. Kuglin

   50  35  15

Mark Wienberg

   46  37  17

Steven C. Boyd

   46  37  17

Douglas T. Brinkworth

   46  37  17

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

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 the Partnership, tenure with the Partnership,Suburban, individual performance and years of experience in his or her current position. The relative importance assigned to each of these factors by the Committee may differ from executive to executive. The Committee will also consider the existing level of equity ownership of each of our named executive officers when granting awards under our Restricted Unit PlansPlan (see below for a description of these plans)this plan). 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 managementsenior level executive officers 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.

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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 ishas been 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. This year, in order to facilitate the succession planning process, the Committee engaged the services of Towers Watson to make recommendations regarding the compensation packages provided to the executive officers the Committee identified as the Partnership’s senior level executive officers. In accordance with this process, and the philosophy described above,a tentative plan of succession discussed by the Committee did not adjust the base salaries of the named executive officers during fiscal 2011; instead,at its November 13, 2013 meeting, the Committee decided to increase eachpostpone discussions of base salary adjustments for our senior level executive officers until its January 22, 2014 Committee meeting when the results of the bonus target percentages of eachTowers Watson study would be made available.

In accordance with the recommendations contained in the Towers Watson study, the Committee adjusted the base salaries of the named executive officers (with the exception of Mr. Dunn’s, whose bonus target percentage was alreadyDunn who retired at 100%)the conclusion of fiscal 2014). The Committee reasoned that this action would further alignThese adjustments became effective on April 1, 2014, the interestseffective date of management with the interests of our Unitholders. Mr. Stivala’s promotion to President; Mr. Kuglin’s promotion to Vice President—Finance and Chief Accounting Officer; Mr. Wienberg’s promotion to Chief Operating Officer; Mr. Boyd’s promotion to Senior Vice President—Field Operations; and Mr. Brinkworth’s promotion to Senior Vice President – Product Supply, Purchasing & Logistics.

Name

  Fiscal 2014
Base Salary
(Second Six Months
of Fiscal Year)
   Fiscal 2014
Base Salary
(First Six Months
of Fiscal Year)
   Fiscal 2013
    Base Salary    
 

Michael J. Dunn, Jr.

  $495,000    $495,000    $495,000  

Michael A. Stivala

  $425,000    $300,000    $300,000  

Michael A. Kuglin

  $265,000    $240,000    $240,000  

Mark Wienberg

  $325,000    $280,000    $280,000  

Steven C. Boyd

  $315,000    $290,000    $290,000  

Douglas T. Brinkworth

  $300,000    $270,000    $270,000  

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 July 22, 2014, effective September 28, 2014, the Committee increased Mr. Kuglin’s salary to $275,000, in recognition of his promotion to Chief Financial Officer and Chief Accounting Officer.

At its meeting on November 11, 2014, the Committee did not adjust the base salaries of our named executive officers for fiscal 2015 because their salaries were adjusted on April 1, 2014.

The total base salarysalaries paid to eachthe named executive officerofficers in fiscal 2011 is2014, fiscal 2013 and fiscal 2012 are reported in the column titled “Salary ($)”“Salary” in the Summary Compensation Table below.

Annual Cash Bonus Plan

Annual cash bonuses (which fall within the SEC’sSecurities 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 2011, ranged from 80% to 100%) of our named executive officers’ annual base salaries (“target cash bonus”) if, for the fiscal year, actual cash bonus plan EBITDA equals the Partnership’s budgeted EBITDA. For purposes of calculating cash bonus plan EBITDA, the Committee customarily adjusts both budgeted and actual EBITDA (as defined in Item 6 in this annual report on Form 10-K) for various items considered to be non-recurring in nature; including, but not limited to, unrealized (non-cash) gains or losses on changes in the fair value of derivative instruments reported within cost of products sold in our statement of operationsinstruments; acquisition-related costs; integration-related costs; multiemployer pension plan withdrawal charges; pension settlement charges; and gains or losses on the disposal of discontinued operations.debt extinguishment. Under the previousprovisions of the annual cash bonus plan in effect for fiscal 2014, our executive officers had the opportunity to earn between 90% and 110% of their target cash bonuses; however, beginning with fiscal 2011, executive officers have the opportunity to earn between 60% and 120% of their target cash bonuses, depending upon the Partnership’s EBITDA performance induring the fiscal year. Under the existing annual cash bonus plan, noNo bonuses arewould be earned during fiscal 2014 if actual cash bonus plan EBITDA iswere less than 90% of budgeted cash bonus plan EBITDA, andEBITDA; additionally, for fiscal 2014, cash bonuses cannotcould not exceed 120% of the target cash bonus even if actual cash bonus plan EBITDA iswere more than 120% of budgeted cash bonus plan EBITDA.

Although our annual cash bonus plan is generally administered usingin accordance with the formula described above,provisions of the plan, 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 to the executive officers as a group, when the Committee recognizes that an adjustment is warranted. During fiscal 2011,2014, fiscal 20102013 and fiscal 2009,2012, no such discretionary adjustments were made to the annual cash bonuses earned by our executives.

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For fiscal 2011,2014, our budgeted cash bonus plan EBITDA was $195$360.0 million (“Budgeted EBITDA”). Our actual cash bonus plan EBITDA was such that each of our executive officers earned 60%68% of his or her target cash bonus. The following table provides the fiscal 20112014 budgeted cash bonus plan EBITDA targets that were established at the November 9, 2010 Compensation13, 2013 Committee meeting:
           
    Hypothetical Fiscal 2011    
    Cash Bonus Plan EBITDA  Target Bonus Percentage that 
Hypothetical Fiscal 2011  Expressed as a  would have been Earned if 
Cash Bonus Plan EBITDA  Percentage of  Actual Cash Bonus Plan 
Results  Budgeted Cash Bonus Plan  EBITDA Equaled the Figure 
(in Millions)  EBITDA  in the First Column 
$234.0   120%  120%
$214.5   110%  110%
$195.0(1)  100%  100%
$185.3   95%  90%
$175.5   90%  60%

Hypothetical Fiscal 2014 Cash Bonus Plan EBITDA Results

(in Millions)

  Hypothetical Fiscal
2014 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
 

$432.0

   120  120

$396.0

   110  110

$360.0(1)

   100  100

$342.0

   95  90

$324.0

   90  60

(1)Budgeted cash bonus plan EBITDA for fiscal 2011.2014.
The bonuses earned under the annual cash bonus plan by each

For those named executive officers who were promoted on April 1, 2014 (all of our named executive officers except Mr. Dunn), actual payments earned are reportedequal to one half of what the payment would have been using each named executive officer’s base salary and bonus percentage in effect for the column titled “Non-Equity Incentive Plan Compensation ($)”first half of fiscal 2014, plus one half of what the payment would have been using each named executive officer’s base pay and bonus percentage in effect for the Summary Compensation Table below.

second half of fiscal 2014. The fiscal 20112014 target cash bonus percentages for both halves of the year and the blended target cash bonuses established for each named executive officer and the actual cash bonuses earned by each of them during fiscal 20112014 are summarized as follows:
             
  2011 Target Cash       
  Bonus as a % of  2011 Target Cash  2011 Actual Cash 
Name Base Salary  Bonus  Bonus Earned 
Michael J. Dunn, Jr.  100% $475,000  $285,000 
Michael A. Stivala  80% $220,000  $132,000 
Steven C. Boyd  80% $216,000  $129,600 
Mark Wienberg  80% $200,000  $120,000 
Douglas T. Brinkworth  80% $196,000  $117,600 

Name

  2014 Target Cash
Bonus as a % of
Base Salary
(for the First Half
of the Fiscal Year)
  2014 Target Cash
Bonus as a % of
Base Salary
(for the Second Half
of the Fiscal Year)
  2014 Target
Cash Bonus
   2014 Actual
Cash Bonus
Earned at 68%
 

Michael J. Dunn, Jr.

   100  100 $495,000    $336,600  

Michael A. Stivala

   80  100 $332,500    $226,100  

Michael A. Kuglin

   65  70 $170,750    $116,110  

Mark Wienberg

   80  80 $242,000    $164,560  

Stephen C. Boyd

   80  80 $242,000    $164,560  

Douglas T. Brinkworth

   80  80 $228,000    $155,040  

For purposes of establishing the cash bonus targets for fiscal 2011,2014, the Committee reviewed and approved our fiscal 20112014 budgeted cash bonus plan EBITDA at its November 9, 201013, 2013 meeting. The budgeted cash bonus plan EBITDA is developed annually using a bottom-up process factoring in reasonable growth targets from the prior year’s performance, while at the same time attempting to reach a good balance between a target that is reasonably achievable, yet not assured. As described above, during fiscal 2014, our executive officers havehad 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%68%, 100%,60% and 110%0% of their respective target cash bonus for fiscal 2011,2014, fiscal 20102013 and fiscal 2009,2012, respectively.

2003

With the exception of Mr. Kuglin (and Mr. Dunn who has retired), the named executive officers’ target cash bonus percentages and target cash bonuses for fiscal 2015 are the same as those for the second half of fiscal 2014. In recognition of his promotion to Chief Financial Officer and Chief Accounting Officer, Mr. Kuglin’s fiscal 2015 target cash bonus has been increased to 75% of his base salary. Actual payments for fiscal 2015 under the annual cash bonus plan will depend upon the percentage of the budgeted cash bonus plan EBITDA for fiscal 2015 that is eventually achieved.

In accordance with recommendations from Towers Watson, the Committee modified the terms of our annual cash bonus plan, beginning with fiscal 2015, to provide our executive officers with the opportunity to earn between 50% and 120% of their target cash bonuses, depending upon the Partnership’s EBITDA performance during the fiscal year. No bonuses will be earned during fiscal 2015 if actual cash bonus plan EBITDA is less than 85% of budgeted cash bonus plan EBITDA; additionally, for fiscal 2015, 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.

The bonuses earned by our named executive officers under the annual cash bonus plan for fiscal 2014 and 2013 are reported in the column titled “Non-Equity Incentive Plan Compensation” in the Summary Compensation Table below.

Long-Term Incentive Plan

At the beginning of fiscal 2003, we adopted the 2003 Long-Term Incentive Plan (“LTIP”), a phantom unit plan, as a principal component of our executive compensation program.

While the annual cash bonus plan is a pay-for-performance plan that focuses on our short-term financial goals, the LTIPLong-Term Incentive Plan, which we hereafter refer to as the “LTIP,” is structured as a phantom 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 payments, if any, are earned and paid at the end of a three-year measurement period, depending on performance.

The LTIP measuresis 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. In accordance with recommendations from Towers Watson, 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 Phantom 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 each 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 2014 and fiscal 2013 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 2016 for the fiscal 2014 award and at the end of fiscal 2015 for the fiscal 2013 award):

   Fiscal
2014
Award
   Fiscal
2013
Award
 

Michael J. Dunn, Jr.

   5,404     6,559  

Michael A. Stivala

   2,620     3,180  

Michael A. Kuglin

   1,703     2,067  

Mark Wienberg

   2,445     2,968  

Steven C. Boyd

   2,533     3,074  

Douglas T. Brinkworth

   2,358     2,862  

At its meeting on November 11, 2014, the Committee approved the grant of the following number of unvested LTIP unit awards under the LTIP for the fiscal 2015 award cycle that commenced at the beginning of fiscal 2015 and will conclude at the end of fiscal 2017 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 2017).

Fiscal
2015
Award

Michael A. Stivala

4,770

Michael A. Kuglin

2,315

Mark Wienberg

2,918

Steven C. Boyd

2,828

Douglas T. Brinkworth

2,694

Performance Metrics

The primary difference between the 2003/2013 LTIPs and the 2014 LTIP is the performance metric used to determine whether cash payments 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, (“TRU”)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 predeterminedfiscal 2013 LTIP award is the only remaining award subject to this metric.

The following table lists, in alphabetical order, the names and ticker symbols of the peer group may vary from year-to-year, but for all outstanding awards, includes AmeriGas Partners, L.P., Ferrellgas Partners, L.P. and Inergy, L.P. (the other propane master limited partnerships). Unvested awards are granted at the beginning of each fiscal year as a Committee-approved percentage of each executive officer’s salary. Cash payouts, if any, are earned and paid at the end ofused to measure our performance during the three-year measurement period.

period for the fiscal 2013 LTIP award:

 

60


The LTIP is designed to:

Fiscal 2013 Award Peer Group

Peer Group Member Name

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

Ticker Symbol

Atlas Pipeline Partners, L.P. Provide long-term compensation opportunities consistent with market practice;APL
AmeriGas Partners, L.P. Reward long-term value creation; andAPU
BreitBurn Energy Partners, L.P. ProvideBBEP
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 2013 award, as a retention incentiveresult of this event, we have reduced the peer group of this award 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. For purposes of measuring relative TRU for our executive officers and other key employees.the fiscal 2013 award, as a result of this event, we have reduced the peer group of this award by one member.

The three-year measurement period of the fiscal 2012 award ended simultaneously with the conclusion of fiscal 2014. The TRU for the fiscal 2012 award fell within the lowest quartile; therefore, the participants, including our named executive officers, did not earn cash payments 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 cash payments under the 2014 LTIP will be determined based on the level of our distribution coverage ratio over a three-year measurement period (“Distribution Coverage Ratio”). 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 LTIP 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, “LTIP 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 executive officer’s unvested award of phantom unitsthe three years in an award’s three-year measurement period. Baseline cash flow is calculated by dividing a predetermined percentage (i.e., 52%), established upon adoptionmultiplying the total number of the LTIP, of the executive officer’s target cash bonus by the average of the closing prices of our Common Units for the twenty days precedingoutstanding 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 year. At2013 award), 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 payoutpayment 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 phantom units multiplied by the average of the closing prices of our Common Units for the twenty days preceding the conclusion of the three-year measurement period;
The quantity of the participant’s phantom units multiplied by the sum of the distributions that would have inured to one of our outstanding Common Units during the three-year measurement period; and
The 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.
The three-year measurement period of the fiscal 2009 award ended simultaneously with the conclusion of fiscal 2011. The TRU for the fiscal 2009 award fell within the second highest quartile. The following is a summary ofquartile; and 125% if our performance falls within the cash payouts related to the fiscal 2009 award earned by our named executive officers at the conclusion of fiscal 2011.top quartile.
     
Michael J. Dunn, Jr. $350,057(1)
Michael A. Stivala $160,609(1)
Steven C. Boyd $160,609(1)
Mark Wienberg $123,962(1)
Douglas T. Brinkworth $139,008(1)
(1)The cash payouts related to our named executive officers’ fiscal 2009 awards earned at the conclusion of fiscal 2011 is an additional disclosure that bears no meaningful relationship to the estimated probable outcomes reported in column (e) of the Summary Compensation Table below.
The following is a summary of the quantity of phantom units that signify the unvested

For awards granted to our named executive officers duringunder the 2014 plan document (the fiscal 2011 and fiscal 2010 that will be used to calculate cash payments2014 award payable, if earned, at the end of each award’s respective three-year measurement period (i.e.fiscal 2016 and the fiscal 2015 award, payable, if earned, at the end of fiscal 2017), at the end of fiscal 2013the 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 payments equal to:

The quantity of the participant’s LTIP units multiplied by the average of the closing prices of our Common Units for the fiscal 2011 award and attwenty days preceding the endconclusion of fiscal 2012 for the fiscal 2010 award):
         
  Fiscal  Fiscal 
  2011 Award  2010 Award 
Michael J. Dunn, Jr.  4,787   5,981 
Michael A. Stivala  2,217   2,597 
Steven C. Boyd  2,177   2,550 
Mark Wienberg  2,016   2,203 
Douglas T. Brinkworth  1,975   2,314 
three-year measurement period;

 

61


The membersquantity of the peer groups selectedparticipant’s LTIP units multiplied by the Committee for the fiscal 2011, fiscal 2010 and fiscal 2009 awards consist entirely of publicly-traded partnerships. The Committee decided upon these peer groups because all publicly-traded partnerships have similar tax attributes and can, as a result, distribute more cash than similarly-sized corporations generating similar revenues. At its November 10, 2009 meeting, the Committee reviewed the performance of eachsum of the membersdistributions that would have inured to one of our outstanding Common Units during the three-year measurement period; and

The sum of the peer group used for the fiscal 2009 and fiscal 2008 LTIP awards and, as a result, replaced twoproducts of the members oftwo preceding calculations multiplied by the peer group forapplicable percentage corresponding to the fiscal 2011 and fiscal 2010 LTIP awards. Among other factors,Distribution Coverage Ratio illustrated in reaching its decision to replace two members of the current peer group, the Committee considered distributions and price fluctuations.
The following tables list, in alphabetical order, the names and ticker symbols of the peer group used to measure our performance during the fiscal 2011, fiscal 2010 and fiscal 2009 LTIP awards’ three-year measurement periods:table:
Fiscal 2011 and Fiscal 2010 LTIP Award Peer Group
Peer Group Member NameTicker Symbol
AmeriGas Partners, L.P.APU
Copano Energy, LLCCPNO
Dorchester Minerals, L.P.DMLP
Enbridge Energy Partners, L.P.EEP
Energy Transfer Partners, L.P.ETP
Ferrellgas Partners, L.P.FGP
Global Partners, L.P.GLP
Inergy, L.P.NRGY
MarkWest Energy Partners, L.P.MWE
Plains All American Pipeline, L.P.PAA
Sunoco Logistics Partners, L.P.SXL
Fiscal 2009 LTIP Awards Peer Group
Peer Group Member NameTicker Symbol
AmeriGas Partners, L.P.APU
Copano Energy, LLCCPNO
Crosstex Energy, L.P.XTEX
Dorchester Minerals, L.P.DMLP
Energy Transfer Partners, L.P.ETP
Ferrellgas Partners, L.P.FGP
Inergy, L.P.NRGY
MarkWest Energy Partners, L.P.MWE
Plains All American Pipeline, L.P.PAA
Star Gas Partners, L.P.SGU
Sunoco Logistics Partners, L.P.SXL
On January 24, 2008, the Committee amended the retirement provisions of the plan document to provide that a

Distribution Coverage Ratio

  % of
Award
Earned
 

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 such awardswill remain subject to the same three-year measurement period for purposes of determining the eventual cash payout,payment, if any, at the conclusion of the measurement period.

The grant date values based on the probable outcomes of the awards under the LTIP awards granted during fiscal 2014, fiscal 2013 and fiscal 2012 (although the final measurement of the fiscal year2012 award resulted in no actual payments to our executive officers) are reported in the column titled “Unit Awards ($)”Awards” in the Summary Compensation Table below.

62


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

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 (collectively and individual referred to as the “RUP”) are substantially identical. At the conclusion of fiscal 2011,2014, there remained 967,594417,758 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, in accordance with recommendations from Towers Watson, the Committee amended the Partnership’s 2009 Restricted Unit Plan to revise the normative vesting schedule of awards granted thereafter to one third 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 meetmeets 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;

1.The unvested award has been held by the grantee for at least six months;
2.The grantee is age 55 or older; and
3.The grantee has worked for us or one of our predecessors for at least 10 years.

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

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

To attract skilled and capable candidates to fill vacant positions;
To retain the services of an employee;
To provide an adequate compensation package to accompany an internal promotion; and
To reward outstanding performance.

 

To retain the services of an employee;

63

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 executive officer’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.

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

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

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

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

On October 31, 2007,

At its November 13, 2013 meeting, in order to further align the interests of management with the interests of our Unitholders the Committee adopted a general policy with respect toapproved the effective grant date of subsequent awards of restricted units under the RUP which states that:

Unless the Committee expressly determines otherwise for a particular award at the time of its approval of such award, the effective date of grant of all awards of restricted units under the RUP in a given calendar year will be the first business day in the month of December of that calendar year. If, at the discretion of the Committee, an award is expressed as a dollar amount, then such award will be converted into the number of restricted units, as of the effective date of grant, obtained by dividing the dollar amount of the award by the average of the closing prices, on the New York Stock Exchange, of one Common Unit of the Partnership for the 20 trading days immediately prior to that effective date of grant.
During fiscal 2011, RUP awards were grantedfollowing grants to the following named executive officers:

Grant Name

  

Grant Name

Date

  Quantity 

Michael A. Stivala

November 15, 2013   5,302

Michael A. Kuglin

November 15, 2013   4,242  
Michael J. Dunn, Jr.

Mark Wienberg

  December 1, 2010November 15, 2013   9,0605,302  
Michael A. Stivala

Steven C. Boyd

  December 1, 2010November 15, 2013   5,4365,302  
Steven C. Boyd

Douglas T. Brinkworth

  December 1, 2010November 15, 2013   5,436
Mark WienbergDecember 1, 20105,436
Douglas T. BrinkworthDecember 1, 20105,4365,302  
In connection with Mr. Dunn’s assumption of additional responsibilities as the Partnership’s Chief Executive Officer at the commencement of fiscal 2010, the Committee, at its November 10, 2009 meeting, granted Mr. Dunn a RUP award, as of December 1, 2010, equal in value to $500,000. The Committee made this award because it believes that equity compensation is a critical component of executive compensation that helps to retain and motivate our executives and because the Committee wished to mitigate a perceived shortfall between the cash components of Mr. Dunn’s compensation and the mean compensation for a comparable position reported in the Mercer database. This RUP award was converted into 9,060 restricted units on the grant date using the formula set forth above. The terms of Mr. Dunn’s award are such that the entire award will vest on the last day of fiscal 2012 and at no time between the grant date and this vesting date will this award be subject to the vesting upon retirement provisions of the RUP described above.

In determining thethese fiscal 20112014 awards for Mr. Stivala, Mr. Boyd,Kuglin, Mr. Wienberg, Mr. Boyd 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.

achievements throughout fiscal 2013. No award was granted to our Chief Executive Officer at the Committee’s November 13, 2013 meeting.

At its January 22, 2014 meeting, in accordance with the recommendations of Towers Watson, in recognition of Mr. Dunn’s years of service to the Partnership and in recognition of the promotions of the senior level executive officers, the Committee approved the following grants to the named executive officers:

Grant Name

Grant Date

Quantity

Michael J. Dunn, Jr.

March 1, 201417,009

Michael A. Stivala

April 1, 201423,885

Michael A. Kuglin

April 1, 201411,943

Mark Wienberg

April 1, 201411,943

Steven C. Boyd

April 1, 201411,943

Douglas T. Brinkworth

April 1, 201411,943

The aggregate grant date fair values of RUP awards made during the fiscal year2014, fiscal 2013 and fiscal 2012, computed in accordance with accounting principles generally accepted in the United States of America isare reported in the column titled “Unit Awards ($)”Awards” in the Summary Compensation Table below.

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At its November 11, 2014 meeting, the Committee did not grant any additional RUP awards to our named executive officers because each of these individuals was granted an award on April 1, 2014.


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 executivesexecutive officers are expected to maintain. The Equity Holding Policy can be accessed through a link on the Partnership’sour website atwww.suburbanpropane.com under the “Investors” tab.

The Partnership’s equity holding requirements are as follows:

Position

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

As of the January 3, 20112, 2014 measurement date, all of our executive officers, including our named executive officers, as well as the members of our Board of Supervisors, were in compliance with the Partnership’sour Equity Holding Policy.

Incentive Compensation Recoupment Policy

On April 25, 2007, upon

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

Of our named executive officers, with the exception ofonly Mr. StivalaDunn, Mr. Boyd, and Mr. Wienberg, participatesBrinkworth participate in the plan. The changes in the actuarial value relative to each named executive officer’stheir participation in the plan isduring fiscal 2014, fiscal 2013 and fiscal 2012 are reported in the column titled “Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)”Earnings” in the Summary Compensation Table below.

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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, (thewhich we refer to as the “401(k) Plan”),Plan,” in which participants may defer a portion of their eligible cash compensation up to the limits established by law. We offer the 401(k) Plan to attract and retain talented employees by providing them with a tax-advantaged opportunity to save for retirement.

For fiscal 2011,2014, 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 2014, fiscal 2013 and fiscal 2012 are included in the column titled “Salary ($)”“Salary” in the Summary Compensation Table below.

In order to be competitive with other employers, if certain performance criteria are met, we will match our employee-participants’ contributions up to the lesser of 6% of their base salary or $245,000,$260,000, 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…
 
Percentage ofWill Receive this Matching
Budgeted EBITDA(1)Contribution for the Year

115% or higher

   100%

100% to 114%

   50%

90% to 99%

   25%

Less than 90%

   0%

(1)For additional information regardingpurposes of the non-GAAP401(k) Plan, the definition of the term “Budgeted EBITDA,” refer“budgeted EBITDA” is identical to the explanation providedthat of “budgeted cash bonus plan EBITDA” discussed under the subheadingheading titled “Annual Cash Bonus Plan” above.
For fiscal 2011, our budgeted

Actual cash bonus plan EBITDA, when applied to the 401(k) Plan, EBITDA was $195.0 million. Based on actual fiscal 2011 401(k) Plan EBITDA results, each of our executive officers earned a matching contribution of 25%. As a result,such that we will provide participants in the 401(k) Plan with a matchmatching contribution equal to 25% of their calendar year 20112014 contributions that diddo not exceed 6% of their total base pay, up to a maximum base payannual compensation limit of $245,000.$260,000. The matching contributions that we will makemade on behalf of our named executive officers for 2014 are reported in the column titled “All Other Compensation ($)”Compensation” in the Summary Compensation Table below.

Supplemental Executive Retirement Plan
In 1998, we adopted a non-qualified, unfunded supplemental retirement plan known as the Suburban Propane Company Supplemental Executive Retirement Plan (the “SERP”). The purpose of the SERP was to provide certain of our executive officers with a level of retirement income from us, without regard to statutory maximums, including the IRC’s limitation for defined benefit plans. In light of the conversion of the Pension Plan to a cash balance formula as described under the subheading “Pension Plan” above, the SERP was amended and restated effective January 1, 1998. The annual retirement benefit under the SERP represents the amount of annual benefits that the participants in the SERP would otherwise be eligible to receive, calculated using the same pay-based credits referenced in the “Pension Plan” section above, applied to the amount of annual compensation that exceeds the IRC’s statutory maximums for defined benefit plans, which was $200,000 in 2002. Effective January 1, 2003, the SERP was discontinued with a frozen benefit determined for the remaining participants.
At the conclusion of fiscal 2010, Mr. Dunn was the only remaining participant in the SERP. Due to the actuarial costs and administrative burdens associated with maintaining this plan for one participant, at its November 9, 2010 meeting, the Committee terminated the SERP and paid Mr. Dunn his accrued benefit of $57,611 on December 1, 2010. Because Mr. Dunn received no above-market interest credits relative to the SERP during fiscal years 2010 and 2009, nothing related to Mr. Dunn’s participation in the SERP is reported in the Summary Compensation Table below.

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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 2014, fiscal 2013 and fiscal 2012 are reported in the column titled “All Other Compensation ($)”Compensation” in the Summary Compensation Table below.

Perquisites

Perquisites represent a minor component of our executive officers’ compensation. Each of the named executive officers is eligible for tax preparation services, a company-provided vehicle, and an annual physical. The following table summarizes both the value and the utilization of these perquisites by the named executive officers in fiscal 2011.

             
      Employer-    
  Tax Preparation  Provided    
Name Services  Vehicle  Physical 
Michael J. Dunn, Jr. $7,700  $16,302  $1,300 
Michael A. Stivala $-0-  $14,698  $-0- 
Steven C. Boyd $7,200  $7,221  $-0- 
Mark Wienberg $-0-  $11,970  $1,300 
Douglas T. Brinkworth $5,100  $10,851  $1,300 
2014.

Name

  Tax
Preparation
Services
   Employer-
Provided
Vehicle
   Physical 

Michael J. Dunn, Jr.

  $9,150    $16,549    $1,600  

Michael A. Stivala

  $-0-    $18,153    $-0-  

Michael A. Kuglin

  $-0-    $12,725    $-0-  

Mark Wienberg

  $-0-    $13,142    $1,750  

Steven C. Boyd

  $4,450    $6,837    $-0-  

Douglas T. Brinkworth

  $4,400    $11,410    $1,500  

Perquisite-related costs for fiscal 2014, fiscal 2013 and fiscal 2012 are reported in the column titled “All Other Compensation ($)”Compensation” in the Summary Compensation Table below.

Impact of Accounting and Tax Treatments of Executive Compensation

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

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

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Letter Agreement of Mr. Dunn

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

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

If on or after the last day of fiscal 2012, Mr. Dunn retires or leaves as a result of an agreed-upon succession plan, he will receive the following:
A lump sum payment equal to two years of base salary.
Payment of medical benefits until attainment of age 65 (Mr. Dunn will be 63 at the conclusion of fiscal 2012).
Payment of unvested LTIP awards held by Mr. Dunn at separation in accordance with the terms and conditions of the LTIP plan document.
Transfer of ownership of employer-provided vehicle to Mr. Dunn.
Receipt of other vested and certain unvested benefits including his unvested RUP awards, his earned cash bonus and his vested pension plan balance in accordance with each plan’s terms and conditions.
In return for the foregoing, Mr. Dunn agreed to providefollowing if he timely provides us with a release of all claims he might have against us at the time of his departure.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 had attained age 65 prior to the conclusion of fiscal 2014).

We 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 willwould not be deemed to have retired or terminated his employment if he simply relinquishesrelinquished the title and responsibilities of President but remainsremained 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 would relinquish the role of President on March 31, 2014, and retire as our Chief Executive Officer on September 27, 2014. Accordingly, the retirement provisions of our letter agreement with Mr. Dunn became effective on September 28, 2014, at which time Mr. Dunn was age 65.

The total payments that will be made under this agreement as a result of Mr. Dunn’s retirement are reported in the column titled “All Other Compensation” in the Summary Compensation Table below.

Severance Benefits

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

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

Change of Control

Our executive officers and other key employees have built the Partnership into the successful enterprise that it is today; therefore, we believe that it is important to protect them in the event of a change of control. Further, it is our belief that the interests of our Unitholders will be best served if the interests of our executive officers are aligned with them, and that providing change of control benefits should eliminate, or at least reduce, the reluctance of our executive officers to pursue potential change of control transactions that may be in the best interests of our Unitholders. Additionally, we believe that the severance benefits provided to our executive officers and to our key employees are consistent with market practice and appropriate because these benefits are an inducement to accepting employment and because the executive officers have agreed to and are subject to non-competition and non-solicitation covenants for a period following termination of employment. Therefore, our executive officers and other key employees are provided with employment protection following a change of control, (thewhich we refer to as the “Severance Protection Plan”). During fiscal 2011,2014, our Severance Protection Plan covered all executive officers, including the named executive officers.

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The Severance Protection Plan provides for severance payments of either sixty-five65 or seventy-eight78 weeks of base salary and target cash bonuses for such officers and key employees if within one year following a change of control and termination of employment.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 seventy-eight78 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 andparticipants. Also, without regard to whether a participant’s employment is terminated, all outstanding, unvested LTIP awards will vest immediately as if the three-year measurement period for each outstanding award concluded on the date the change of control occurred and our TRU was such that, in relationoccurred. Under the provisions of the LTIP document, an amount equal to the performancecash value of 125% of a participant’s unvested LTIP units plus a sum equal to 125% of a participant’s unvested LTIP units multiplied by an amount equal to the other memberscumulative, per-Common Unit distribution from the beginning of an unvested award’s three-year measurement period through the peer group, it fell withindate on which a change of control occurred would become payable to the top quartile.

participants.

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

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, ourthe 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,the Partnership, our subsidiaries, any employee benefit plan maintained by us, ourthe 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, (suchwhich transaction we refer to as a “Non-Control Transaction”); or

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

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

Report of the Compensation Committee

The Compensation Committee has reviewed and discussed with management this Compensation Discussion and Analysis. Based on its review and discussions with management, the Committee recommended to the Board of Supervisors that this Compensation Discussion and Analysis be included in this Annual Report on Form 10-K for fiscal 2011.

2014.

The Compensation Committee:

John Hoyt Stookey, Chairman
John D. Collins

Matthew J. Chanin

Harold R. Logan, Jr.
Dudley C. Mecum
Jane Swift

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ADDITIONAL INFORMATION REGARDING EXECUTIVE COMPENSATION

Summary Compensation Table for Fiscal 2011

The following table sets forth certain information concerning the compensation of each named executive officer during the fiscal years ended September 24, 2011,27, 2014, September 25, 2010,28, 2013 and September 26, 2009:

                                 
                      Change in       
                      Pension Value       
                      and       
                      Nonqualified       
                  Non-Equity  Deferred       
              Unit  Incentive  Compensation  All Other    
Name and Principal     Salary  Bonus  Awards  Plan Compen-  Earnings  Compensation  Total 
Position Year  ($)(1)  ($)  ($)(2)  sation ($)(3)  ($)(4)  ($)(5)  ($) 
(a) (b)  (c )  (d)  (e)  (g)  (h)  (i)  (j) 
Michael J. Dunn, Jr.  2011  $475,000     $729,076  $285,000  $3,764  $49,530  $1,542,370 
President and Chief  2010  $475,000     $768,484  $475,000  $31,661  $49,330  $1,799,475 
Executive Officer  2009  $433,333     $314,197  $467,500  $56,050  $48,065  $1,319,145 
                                 
Michael A. Stivala  2011  $275,000     $357,103  $132,000     $35,010  $799,113 
Chief Financial Officer  2010  $275,000     $320,699  $206,250     $37,569  $839,518 
   2009  $262,500     $231,333  $214,500     $41,728  $750,061 
                                 
Steven C. Boyd  2011  $270,000     $354,615  $129,600  $15,257  $37,095  $806,567 
Vice President of  2010  $270,000     $317,799  $202,500  $21,101  $34,762  $846,162 
Field Operations  2009  $260,000     $190,660  $214,500  $53,577  $39,811  $758,548 
                                 
Mark Wienberg  2011  $250,000     $344,653  $120,000     $33,725  $748,378 
Vice President of  2010  $250,000     $273,398  $175,000     $35,755  $734,153 
Operational Support  2009  $220,833     $157,386  $165,550     $40,348  $584,117 
and Analysis                                
                                 
Douglas T. Brinkworth  2011  $245,000     $342,155  $117,600  $10,245  $39,156  $754,156 
Vice President of  2010  $245,000     $303,237  $183,750  $12,959  $41,767  $786,713 
Product Supply  2009  $228,333     $182,883  $185,625  $31,679  $43,440  $671,960 
29, 2012:

Name and Principal Position

  Year   Salary
($)(1)
   Bonus
($)(2)
   Unit Awards
($)(3)
   Non-Equity
Incentive Plan
Compensation
($)(4)
   Change in
Pension Value
and
Nonqualified
Deferred
Compensation
Earnings

($)(5)
   All Other
Compensation
($)(6)
   Total
($)
 
(a)  (b)   (c )   (d)   (e)   (g)   (h)   (i)   (j) 

Michael J. Dunn, Jr.

Former Chief Executive Officer (Retired at the Conclusion of Fiscal 2014)

   2014    $495,000     —      $981,921    $336,600    $9,102    $48,352    $1,870,975  
   2013    $495,000     —      $369,124    $297,000     —      $54,619    $1,215,743  
   2012    $475,000     —      $521,058     —      $22,308    $49,280    $1,067,646  

Michael A. Stivala

President and Chief Executive Officer

   2014    $362,500     —      $1,182,776    $226,100     —      $40,906    $1,812,282  
   2013    $300,000     —      $376,313    $144,000     —      $42,073    $862,386  
   2012    $275,000     —      $328,487     —       —      $36,557    $640,044  

Michael A. Kuglin

Chief Financial Officer and Chief Accounting Officer

   2014    $252,500     —      $675,618    $116,110     —      $33,430    $1,077,658  
   2013    $240,000     —      $257,297    $93,600     —      $35,161    $626,058  
   2012    $215,000     —      $215,211     —       —      $28,715    $458,926  

Mark Wienberg

Chief Operating Officer

   2014    $302,500     —      $758,784    $164,560     —      $37,800    $1,263,644  
   2013    $280,000     —      $364,382    $134,400     —      $36,055    $814,837  
   2012    $250,000     —      $317,553     —       —      $32,854    $600,407  

Steven C. Boyd

Senior Vice President—Field Operations

   2014    $302,500     —      $763,708    $164,560    $28,917    $35,341    $1,295,026  
   2013    $290,000     —      $370,348    $139,200     —      $33,416    $832,964  
   2012    $270,000     —      $326,310     —      $41,823    $32,763    $670,896  

Douglas T. Brinkworth

Senior Vice President—Product Supply, Purchasing & Logistics

   2014    $285,000     —      $753,870    $155,040    $16,037    $41,416    $1,251,363  
   2013    $270,000     —      $358,418    $129,600     —      $40,772    $798,790  
   2012    $245,000     —      $315,326     —      $24,327    $35,786    $620,439  

(1)Includes amounts deferred by named executive officers as contributions to the qualified 401(k) Plan.
For more information on the relationship between salaries and other cash compensation (i.e., annual cash incentivesbonuses and 2003 Long-Term Incentive Plan awards), refer to the subheading titled “Allocation Among Components” in the “Compensation Discussion and Analysis” above.

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(2)This column is reserved for discretionary cash bonuses that are not based on any performance criteria. During fiscal years 2014, 2013, and 2012, we did not provide our named executive officers with non-performance related bonus payments.

(3)The amounts reported in this column represent the aggregate grant date fair value of RUP awards made during fiscal years 2011, 20102014, 2013 and 2009,2012, as well as the value at the grant date of LTIP awards made in fiscal years 2011, 2010,2014, 2013, and 2009,2012 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 Plans”Plan” and “2003 Long-Term“Long-Term Incentive Plan.” The breakdown for each plan with respect to each named executive officer is as follows:

                     
Plan Name Mr. Dunn  Mr. Stivala  Mr. Boyd  Mr. Wienberg  Mr. Brinkworth 
2011
                    
RUP $433,249  $220,090  $220,090  $220,090  $220,090 
LTIP  295,827   137,013   134,525   124,563   122,065 
                
Total
 $729,076  $357,103  $354,615  $344.653  $342,155 
                
                     
2010
                    
RUP $399,438  $160,456  $160,456  $160,456  $160,456 
LTIP  369,046   160,243   157,343   112,942   142,781 
                
Total
 $768,484  $320,699  $317,799  $273,398  $303,237 
                
                     
2009
                    
RUP $  $87,177  $46,504  $58,115  $58,115 
LTIP  314,197   144,156   144,156   99,271   124,768 
                
Total
 $314,197  $231,333  $190,660  $157,386  $182,883 
                

Plan Name

  Mr. Dunn   Mr. Stivala   Mr. Kuglin   Mr. Wienberg   Mr. Boyd   Mr. Brinkworth 

2014

            

RUP

  $677,679    $1,035,266    $579,736    $621,111    $621,111    $621,111  

LTIP

   304,242     147,510     95,882     137,673     142,597     132,759  

Total

  $981,921    $1,182,776    $675,618    $758,784    $763,708    $753,870  

2013

            

RUP

   N/A    $197,351    $140,971    $197,351    $197,351    $197,351  

LTIP

   369,124     178,962     116,326     167,031     172,997     161,067  

Total

  $369,124    $376,313    $257,297    $364,382    $370,348    $358,418  

2012

            

RUP

  $260,900    $208,007    $138,668    $208,007    $208,007    $208,007  

LTIP

   260,158     120,480     76,543     109,546     118,303     107,319  

Total

  $521,058    $328,487    $215,211    $317,553    $326,310    $315,326  

(3)(4)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)(5)The amountsNothing was reported in this column represent eachfor fiscal 2013 because there was a decline in value of the participating named executive officer’sofficers’ Cash Balance Plan earnings and for Mr. Dunn, SERP earningsholdings. The declines in pension values for fiscal years 20102013 were as follows: ($24,140), ($28,591), and 2009. The SERP was discontinued($14,743) for Messrs. Dunn, Boyd, and the balance paid at the conclusion of fiscal 2010; therefore, there are no 2011 SERP earnings reported in the table. NeitherBrinkworth, respectively. Mr. Stivala, norMr. Kuglin and Mr. Wienberg participatesdo not participate in the Cash Balance Plan.
(5)(6)The amounts reported in this column consist of the following:
                     
2011 
Type of Compensation Mr. Dunn  Mr. Stivala  Mr. Boyd  Mr. Wienberg  Mr. Brinkworth 
401(k) Match $3,675  $3,675  $3,675  $3,675  $3,675 
Value of Annual Physical Examination  1,300   N/A   N/A   1,300   1,300 
Value of Partnership Provided Vehicle  16,302   14,698   7,221   11,970   10,851 
Tax Preparation Services  7,700   N/A   7,200   N/A   5,100 
Cash Balance Plan Administrative Fees  1,500   N/A   1,500   N/A   1,500 
Insurance Premiums  19,053   16,637   17,499   16,780   16,730 
                
Totals
 $49,530  $35,010  $37,095  $33,725  $39,156 
                
                     
2010 
Type of Compensation  Mr. Dunn Mr. Stivala  Mr. Boyd  Mr. Wienberg  Mr. Brinkworth 
401(k) Match $7,350  $7,350  $7,350  $7,350  $7,350 
Value of Annual Physical Examination  1,300   1,300   N/A   1,300   1,300 
Value of Partnership Provided Vehicle  13,868   12,903   6,251   10,993   11,966 
Tax Preparation Services  6,500   N/A   3,600   N/A   3,600 
Cash Balance Plan Administrative Fees  1,500   N/A   1,500   N/A   1,500 
Insurance Premiums  18,812   16,016   16,061   16,112   16,051 
                
Totals
 $49,330  $37,569  $34,762  $35,755  $41,767 
                
                     
2009 
Type of Compensation Mr. Dunn  Mr. Stivala  Mr. Boyd  Mr. Wienberg  Mr. Brinkworth 
401(k) Match $14,700  $14,700  $14,700  $13,748  $13,825 
Value of Annual Physical Examination  N/A   1,300   N/A   1,300   N/A 
Value of Partnership Provided Vehicle  12,205   11,318   6,205   10,803   10,610 
Tax Preparation Services  3,000   N/A   3,000   N/A   3,000 
Cash Balance Plan Administrative Fees  1,500   N/A   1,500   N/A   1,500 
Insurance Premiums  16,660   14,410   14,406   14,497   14,505 
                
Totals
 $48,065  $41,728  $39,811  $40,348  $43,440 
                
Note:Column (f) was omitted from the Summary Compensation Table because the Partnership does not grant options to its employees.

 

   2014 

Type of Compensation

  Mr. Dunn   Mr. Stivala   Mr. Kuglin   Mr. Wienberg   Mr. Boyd   Mr. Brinkworth 

401(k) Match

  $3,900    $3,900    $3,788    $3,900    $3,900    $3,900  

Value of Annual Physical Examination

   1,600     N/A     N/A     1,750     N/A     1,500  

Value of Partnership Provided Vehicle

   16,549     18,153     12,725     13,142     6,837     11,410  

Tax Preparation Services

   9,150     N/A     N/A     N/A     4,450     4,400  

Cash Balance Plan Administrative Fees

   1,500     N/A     N/A     N/A     1,500     1,500  

Insurance Premiums

   15,653     18,853     16,917     19,008     18,654     18,706  

Totals

  $48,352    $40,906    $33,430    $37,800    $35,341    $41,416  

71

   2013 

Type of Compensation

  Mr. Dunn   Mr. Stivala   Mr. Kuglin   Mr. Wienberg   Mr. Boyd   Mr. Brinkworth 

401(k) Match

  $3,825    $3,825    $3,600    $3,825    $3,825    $3,825  

Value of Annual Physical Examination

   1,750     1,750     1,750     1,500     N/A     1,750  

Value of Partnership Provided Vehicle

   18,897     19,319     12,882     13,570     7,705     11,521  

Tax Preparation Services

   8,950     N/A     N/A     N/A     2,650     4,050  

Cash Balance Plan Administrative Fees

   1,500     N/A     N/A     N/A     1,500     1,500  

Insurance Premiums

   19,697     17,179     16,929     17,160     17,736     18,126  

Totals

  $54,619    $42,073    $35,161    $36,055    $33,416    $40,772  

   2012 

Type of Compensation

  Mr. Dunn   Mr. Stivala   Mr. Kuglin   Mr. Wienberg   Mr. Boyd   Mr. Brinkworth 

401(k) Match

  $3,000    $3,000    $2,580    $3,000    $3,000    $2,940  

Value of Annual Physical Examination

   N/A     1,500     N/A     1,500     N/A     N/A  

Value of Partnership Provided Vehicle

   17,047     15,480     9,810     11,676     7,743     10,677  

Tax Preparation Services

   8,400     N/A     N/A     N/A     3,150     4,050  

Cash Balance Plan Administrative Fees

   1,500     N/A     N/A     N/A     1,500     1,500  

Insurance Premiums

   19,333     16,577     16,325     16,678     17,370     16,619  

Totals

  $49,280    $36,557    $28,715    $32,854    $32,763    $35,786  

Note: Column (f) was omitted from the Summary Compensation Table because we do not grant options to our employees.


Grants of Plan Based Awards Table for Fiscal 2011
2014

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

                                         
              Phantom  Estimated Future  Estimated Future       
              Units  Payments  Payments  All Other stock  Grant Date 
              Underlying  Under Non-Equity  Under Equity  Awards:  Fair Value of 
              Equity  Incentive  Incentive  Number of  Stock and 
              Incentive  Plan Awards  Plan Awards  Shares of Stock  Option 
  Plan  Grant Approval  Plan Awards  Target  Maximum  Target  Maximum  or Units  Awards 
Name Name  Date Date  (LTIP)(4)  ($)  ($)  ($)  ($)  (#)  ($)(5) 
(a)     (b)          (d)  (e)  (g)  (h)  (i)  (l) 
Michael J. Dunn, Jr. RUP(1) 1 Dec 10 9 Nov 10                      9,060  $433,249 
  Bonus(2) 26 Sep 10         $475,000  $570,000                 
  LTIP(3) 26 Sep 10      4,787          $273,878  $342,362         
                                         
Michael A. Stivala RUP(1) 1 Dec 10 9 Nov 10                      5,436  $220,090 
  Bonus(2) 26 Sep 10         $220,000  $264,000                 
  LTIP(3) 26 Sep 10      2,217          $126,842  $158,538         
                                         
Steven C. Boyd RUP(1) 1 Dec 10 9 Nov 10                      5,436  $220,090 
  Bonus(2) 26 Sep 10         $216,000  $259,200                 
  LTIP(3) 26 Sep 10      2,177          $124,552  $155,677         
                                         
Mark Wienberg RUP(1) 1 Dec 10 9 Nov 10                      5,436  $220,090 
  Bonus(2) 26 Sep 10         $200,000  $240,000                 
  LTIP(3) 26 Sep 10      2,016          $115,342  $144,177         
                                         
Douglas T. Brinkworth RUP(1) 1 Dec 10 9 Nov 10                      5,436  $220,090 
  Bonus(2) 26 Sep 10         $196,000  $235,200                 
  LTIP(3) 26 Sep 10      1,975          $112,996  $141,259         
27, 2014:

               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)  1 Mar 14  22 Jan 14             17,009    $677,679  
  Bonus (2)  29 Sep 13  13 Nov 13    $495,000    $594,000          
  LTIP (3)  29 Sep 13  13 Nov 13  5,404      $304,242    $456,363      

Michael A. Stivala

  RUP (1)  15 Nov 13  13 Nov 13             5,302    $206,924  
  RUP (1)  1 Apr 14  22 Jan 14             23,885    $828,342  
  Bonus (2)  29 Sep 13  13 Nov 13    $332,500    $399,000          
  LTIP (3)  29 Sep 13  13 Nov 13  2,620      $147,510    $221,265      

Michael A. Kuglin

  RUP (1)  15 Nov 13  13 Nov 13             4,242    $165,549  
  RUP (1)  1 Apr 14  22 Jan 14             11,943    $414,187  
  Bonus (2)  29 Sep 13  13 Nov 13    $170,750    $204,900          
  LTIP (3)  29 Sep 13  13 Nov 13  1,703      $95,882    $143,823      

Mark Wienberg

  RUP (1)  15 Nov 13  13 Nov 13             5,302    $206,924  
  RUP (1)  1 Apr 14  22 Jan 14             11,943    $414,187  
  Bonus (2)  29 Sep 13  13 Nov 13    $242,000    $290,400          
  LTIP (3)  29 Sep 13  13 Nov 13  2,445      $137,673    $206,510      

Steven C. Boyd

  RUP (1)  15 Nov 13  13 Nov 13             5,302    $206,924  
  RUP (1)  1 Apr 14  22 Jan 14             11,943    $414,187  
  Bonus (2)  29 Sep 13  13 Nov 13    $242,000    $290,400          
  LTIP (3)  29 Sep 13  13 Nov 13  2,533      $142,597    $213,896      

Douglas T. Brinkworth

  RUP (1)  15 Nov 13  13 Nov 13             5,302    $206,924  
  RUP (1)  1 Apr 14  22 Jan 14             11,943    $414,187  
  Bonus (2)  29 Sep 13  13 Nov 13    $228,000    $273,600          
  LTIP (3)  29 Sep 13  13 Nov 13  2,358      $132,759    $199,139      

(1)The quantities reported on these lines represent awards granted under the Partnership’s Restricted Unit Plans. Generally, RUP awards granted subsequent to fiscal 2013 vest as follows: 25%one third of the award on the first anniversary of the grant date; one third of the award on the second anniversary of the grant date; and one third 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 grantdate, 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 the Partnership for at least ten years, an award held by such participant will vest six months following such participant’s retirement if the participant retires prior to the conclusion of the normal vesting schedule, unless the Committee exercises its authority to alter the applicability of the plan’s retirement provisions in regard to a particular award. On September 24, 2011,27, 2014, Mr. Dunn was the only named executive officer who held RUP awards and, at the same time, satisfied all three retirement eligibility criteria. However, the terms of Mr. Dunn’s fiscal 2011 and fiscal 2010 awards are such that the entire awards will vest on the last day of fiscal 2012 and at no time between the grant date and the vesting date will these awards be subject to the normative retirement provisions of the 2000 or 2009 RUP documents. Detailed discussionsA discussion of the general terms of the RUP, and the facts and circumstances considered by the Committee in authorizing the fiscal 20112014 awards to the named executive officers, is included in the “Compensation Discussion and Analysis” under the subheading “Restricted Unit Plans.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 20112014 were equal to 60%68% of the “Target” amounts reported on this line. Column (c) (“Threshold $”) was omitted because the annual cash bonus plan does not provide for a minimum cash payment. Because these plan awards were granted to, and 60%68% of the “Target” awards were earned by, our named executive officers during fiscal 2011, 60%2014, 68% of the “Target” amounts reported under column (d) have been reported in the Summary Compensation Table above.
(3)The LTIP is a phantom unit plan. Payments, if earned, are based on a combination of (1) the fair market value of our Common Units at the end of a three-year measurement period, which, for purposes of the plan, is the average of the closing prices for the twenty business days preceding the conclusion of the three-year measurement period, and (2) cash equal to the distributions that would have inured to the same quantity of outstanding Common Units during the same three-year measurement period. The fiscal 20112014 award “Target ($)”“Target” and “Maximum ($)”“Maximum” amounts are estimates based upon (1) the fair market value (the average of the closing prices of our Common Units for the twenty business days preceding September 24, 2011)28, 2013) of our Common Units at the endbeginning of fiscal 2011,2014, and (2) the estimated distributions over the course of the award’s three-year measurement period. Column (f) (“Threshold $”Threshold”) was omitted because the LTIP does not provide for a minimum cash payment. The “Target ($)”“Target” amount represents a hypothetical payment at 100% of target and the “Maximum ($)”“Maximum” amount represents a hypothetical payment at 125%150% of target. Detailed descriptions of the plan and the calculation of awards are included in the “Compensation Discussion and Analysis” under the subheading “2003 Long-Term“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 phantomLTIP units each named executive officer was awarded under the LTIP during fiscal 2011.2014.
(5)The dollar amounts reported in this column represent the aggregate fair value of the RUP awards on the grant date, net of estimated future distributions during the vesting period. The fair value shown may not be indicative of the value realized in the future upon vesting due to the variability in the trading price of our Common Units.
Note:Columns (j) and (k) were omitted from the Grants of Plan Based Awards Table because the Partnership does not award options to its employees.

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

72


Outstanding Equity Awards at Fiscal Year End 20112014 Table

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

                 
Stock Awards 
          Equity Incentive    
          Plan Awards:    
          Number of  Equity Incentive Plan 
      Market Value  Unearned  Awards: Market or 
  Number of Shares  of Shares or  Shares, Units or  Payout Value of 
  or Units of Stock  Units of Stock  Other Rights  Unearned Shares, 
  That Have Not  That Have Not  that Have Not  Units or Other Rights 
  Vested  Vested  Vested  That Have Not Vested 
Name (#)(6)  ($)(7)  (#)(8)  ($)(9) 
(a) (g)  (h)  (i)  (j) 
Michael J. Dunn, Jr. (1)
  42,557  $1,965,069   10,768  $615,698 
Michael A. Stivala(2)
  19,813  $914,865   4,814  $275,263 
Steven C. Boyd(3)
  18,417  $850,405   4,727  $270,287 
Mark Wienberg(4)
  16,503  $762,026   4,219  $241,246 
Douglas T. Brinkworth(5)
  17,134  $791,162   4,289  $245,244 
27, 2014:

Stock Awards

 

Name

  Number of Shares
or Units of Stock
That Have Not
Vested

(#)(7)
   Market Value
of Shares or
Units of
Stock That
Have Not
Vested

($)(8)
   Equity Incentive Plan
Awards: Number of
Unearned Shares,
Units or Other
Rights that Have Not
Vested

(#)(9)
   Equity Incentive Plan
Awards: Market or
Payout Value of
Unearned Shares,
Units or Other
Rights That Have
Not Vested

($)(10)
 
(a)  (g)   (h)   (i)   (j) 

Michael J. Dunn, Jr. (1)

   25,009    $1,107,774     11,963    $658,436  

Michael A. Stivala (2)

   50,627    $2,242,523     5,800    $319,229  

Michael A. Kuglin (3)

   30,879    $1,367,785     3,770    $207,499  

Mark Wienberg (4)

   38,685    $1,713,552     5,413    $297,929  

Steven C. Boyd(5)

   38,685    $1,713,552     5,607    $308,606  

Douglas T. Brinkworth (6)

   38,865    $1,713,552     5,220    $287,305  

(1)Despite Mr. Dunn’s having met the plan’s retirement criteria (explained under the subheading “Restricted Unit Plans” in the “Compensation Discussion and Analysis”), the terms of Mr. Dunn’s fiscal 2011 and fiscal 2010 RUP awards of 9,060 and 11,348 unvested units, respectively, are such that the entire awards will vest on the last day of fiscal 2012 and at no time between the grant dates and the vesting date will these awards be subject to the normative retirement provisions of the 2000 or 2009 RUP documents. For more information on this and the retirement provisions, refer to the subheading “Restricted Unit Plans” in the “Compensation Discussion and Analysis.” If Mr. Dunn does not retire prior to the conclusion of the normal vesting schedule of his fiscal 2008 RUP award, his RUP awards will vest as follows:
             
Vesting Dec 3,  Sep 29,  Dec 3, 
Date 2011  2012  2012 
Quantity of Units  7,384   20,408   14,765 

(2)

Vesting Date

  Mar 28
2015

Quantity of Units

25,009

(2)Mr. Stivala’s RUP awards will vest as follows:
                                 
  Dec 1,  Dec 3,  Apr 25,  Dec 1,  Dec 3,  Dec 1,  Dec 1,  Dec 1, 
Vesting Date 2011  2011  2012  2012  2012  2013  2014  2015 
Quantity of Units  1,205   568   2,748   2,482   1,136   5,044   3,912   2,718 

Vesting Date

  Nov 15
2014
   Apr 1
2015
   Nov 15
2015
   Apr 1
2016
   Nov 15
2016
   Apr 1
2017
   Nov 15
2017
 

Quantity of Units

   7,275     7,962     8,189     7,962     7,062     7,961     4,216  

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

Vesting Date

  Nov 15
2014
   Apr 1
2014
   Nov 15
2015
   Apr 1
2016
   Nov 15
2016
   Apr 1
2017
   Nov 15
2017
 

Quantity of Units

   5,084     3,981     5,795     3,981     5,046     3,981     3,011  

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

Vesting Date

  Nov 15
2014
   Apr 1
2015
   Nov 15
2015
   Apr 1
2016
   Nov 15
2016
   Apr 1
2017
   Nov 15
2017
 

Quantity of Units

   7,275     3,981     8,189     3,981     7,062     3,981     4,216  

(5)Mr. Boyd’s RUP awards will vest as follows:
                                 
  Dec 1,  Dec 3,  Apr 25,  Dec 1,  Dec 3,  Dec 1,  Dec 1,  Dec 1, 
Vesting Date 2011  2011  2012  2012  2012  2013  2014  2015 
Quantity of Units  643   852   2,748   1,920   1,704   3,920   3,912   2,718 

Vesting Date

  Nov 15
2014
   Apr 1
2015
   Nov 15
2015
   Apr 1,
2016
   Nov 15
2016
   Apr 1
2017
   Nov 15
2017
 

Quantity of Units

   7,275     3,981     8,189     3,981     7,062     3,981     4,216  

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

                         
  Dec 1,  Apr 25,  Dec 1,  Dec 1,  Dec 1,  Dec 1, 
Vesting Date 2011  2012  2012  2013  2014  2015 
Quantity of Units  803   2,748   2,080   4,292   3,962   2,618 
(5)(6)Mr. Brinkworth’s RUP awards will vest as follows:
                                 
  Dec 1,  Dec 3,  Apr 25,  Dec 1,  Dec 3,  Dec 1,  Dec 1,  Dec 1, 
Vesting Date 2011  2011  2012  2012  2012  2013  2014  2015 
Quantity of Units  803   852   823   2,080   1,704   4,242   3,912   2,718 

Vesting Date

  Nov 15
2014
   Apr 1
2015
   Nov 15
2015
   Apr 1,
2016
   Nov 15
2016
   Apr 1
2017
   Nov 15
2017
 

Quantity of Units

   7,275     3,981     8,189     3,981     7,062     3,981     4,216  

(6)(7)The figures reported in this column represent the total quantity of each of our named executive officer’s unvested RUP awards.
(7)(8)The figures reported in this column represent the figures reported in column (g) multiplied by the average of the highest and the lowest trading prices of our Common Units on September 23, 2011,26, 2014, the last trading day of fiscal 2011.2014.

73


(8)(9)The amounts reported in this column represent the quantities of phantomLTIP units that underlie the outstanding and unvested fiscal 20112014 and fiscal 20102013 awards under the LTIP. Payments, if earned, for the 2013 award, will be made to participants at the end of a three-year measurement period and will be based upon our total return to our 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. Payments if earned, for the 2014 award, will be made to participants at the end of a three-year measurement period and will be based upon the Partnership’s distribution coverage ratio for the three-year measurement period. For more information on the LTIP, refer to the subheading “2003 Long-Term“Long-Term Incentive Plan” in the “Compensation Discussion and Analysis.”
(9)(10)The amounts reported in this column represent the estimated future target payouts of the fiscal 20112014 and fiscal 2010 LTIP-awards.2013 awards granted under the LTIP. These amounts were computed by multiplying the quantities of the unvested phantomLTIP units in column (i) by the average of the closing prices of our Common Units for the twenty business days preceding September 24, 201127, 2014 (in accordance with the plan’s valuation methodology), and by adding to the product of that calculation the product of each year’s underlying phantomLTIP units times the sum of the distributions that are estimated to inure to an outstanding Common Unit during each award’s three-year measurement period. Due to the variability in the trading prices of our Common Units, as well as our performance relative to the peer group, actual payments, if any, at the end of the three-year measurement period may differ. The following chart provides a breakdown of each year’s awards:
                     
  Mr. Dunn  Mr. Stivala  Mr. Boyd  Mr. Wienberg  Mr. Brinkworth 
Fiscal 2011 Phantom Units  4,787   2,217   2,177   2,016   1,975 
Value of Fiscal 2011 Phantom Units $224,893  $104,155  $102,275  $94,712  $92,786 
Estimated Distributions over Measurement Period $48,985  $22,687  $22,277  $20,630  $20,210 
                     
Fiscal 2010 Phantom Units  5,981   2,597   2,550   2,203   2,314 
Value of Fiscal 2010 Phantom Units $280,987  $122,007  $119,799  $103,497  $108,712 
Estimated Distributions over Measurement Period $60,833  $26,414  $25,936  $22,407  $23,536 
Note:Columns (b), (c), (d), (e) and (f), all of which are for the reporting of option-related compensation, have been omitted from the Outstanding Equity Awards At Fiscal Year End Table because we do not grant options to our employees.

   Mr. Dunn   Mr. Stivala   Mr. Kuglin   Mr. Wienberg   Mr. Boyd   Mr. Brinkworth 

Fiscal 2014 LTIP Units

   5,404     2,620     1,703     2,445     2,533     2,358  

Value of Fiscal 2014 LTIP Units

  $240,756    $116,725    $75,871    $108,928    $112,849    $105,052  

Estimated Distributions over Measurement Period

  $56,742    $27,510    $17,882    $25,673    $26,597    $24,759  

Fiscal 2013 LTIP Units

   6,559     3,180     2,067     2,968     3,074     2,862  

Value of Fiscal 2013 LTIP Units

  $292,213    $141,674    $92,088    $132,229    $136,951    $127,506  

Estimated Distributions over Measurement Period

  $68,725    $33,320    $21,658    $31,099    $32,209    $29,988  

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 2014 Table” because we do not grant options to our employees.

Equity Vested Table for Fiscal 2011

2014

Awards under the Restricted Unit Plans are settled in Common Units upon vesting. Awards under the 2003 Long-Term Incentive Plan,LTIP, a phantom-equityLTIP-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 20092012 award under our 2003 Long-Term Incentive PlanLTIP for each named executive officer during the fiscal year ended September 24, 2011:

         
Restricted Unit Plans Unit Awards 
  Number of    
  Common Units    
  Acquired on  Value 
  Vesting  Realized on 
Name (#)  Vesting ($)(1) 
Michael J. Dunn, Jr.  7,384  $410,883 
Michael A. Stivala  4,280  $239,616 
Steven C. Boyd  5,426  $299,272 
Mark Wienberg  3,712  $205,004 
Douglas T. Brinkworth  4,853  $268,877 
27, 2014:

Restricted Unit Plans

  Unit Awards 

Name

  Number of
Common Units
Acquired on
Vesting (#)
   Value
Realized
on Vesting
($)(1)
 

Michael J. Dunn, Jr.

   -0-    $-0-  

Michael A. Stivala

   5,044    $232,680  

Michael A. Kuglin

   4,728    $218,103  

Mark Wienberg

   4,242    $195,683  

Steven C. Boyd

   3,920    $180,830  

Douglas T. Brinkworth

   4,242    $195,683  

(1)The value realized is equal to the average of the high and low trading prices of our Common Units on the vesting date, multiplied by the number of units that vested.
         
2003 Long-Term Incentive Plan — Fiscal 2009(2) Award Cash Awards 
  Number of    
  Phantom Units    
  Acquired on  Value 
  Vesting  Realized on 
Name (#)(3)  Vesting ($)(4) 
Michael J. Dunn, Jr.  6,142  $350,057 
Michael A. Stivala  2,818  $160,609 
Steven C. Boyd  2,818  $160,609 
Mark Wienberg  2,175  $123,962 
Douglas T. Brinkworth  2,439  $139,008 

Long-Term Incentive Plan—Fiscal 2012(2) Award

  Cash Awards 

Name

  Number of
LTIP Units
Acquired
on Vesting
(#) (3)
   Value
Realized on
Vesting
($) (4)
 

Michael J. Dunn, Jr.

   5,258    $0  

Michael A. Stivala

   2,435    $0  

Michael A. Kuglin

   1,547    $0  

Mark Wienberg

   2,214    $0  

Steven C. Boyd

   2,391    $0  

Douglas T. Brinkworth

   2,169    $0  

(2)The fiscal 20092012 award’s three-year measurement period concluded on September 24, 2011.27, 2014.
(3)In accordance with the formula described in the “Compensation Discussion and Analysis” under the subheading “2003 Long-Term“Long-Term Incentive Plan,” these quantities were calculated at the beginning of the three-year measurement period and were, therefore, based upon each individual’s salary and target cash bonus at that time.
(4)The value (i.e., cash payment) realized was calculated in accordance with the terms and conditions of the LTIP. For more information, refer to the subheading “2003 Long-Term“Long-Term Incentive Plan” in the “Compensation Discussion and Analysis.”

74


Pension Benefits Table for Fiscal 2011
2014

The following table sets forth certain information concerning each plan that provides for payments or other benefits at, following, or in connection with retirement for each named executive officer as of the end of the fiscal year ended September 24, 2011:

               
    Number  Present Value    
    of Years  of  Payments 
    Credited  Accumulated  During Last 
    Service  Benefit  Fiscal Year 
Name Plan Name (#)  ($)  ($) 
               
Michael J. Dunn, Jr. Cash Balance Plan (1)  6  $250,122  $ 
  LTIP(3)  N/A  $615,698  $ 
  RUP(4)  N/A  $1,022,730  $ 
  SERP(5)  6  $  $57,611 
               
Michael A. Stivala(2)
 N/A  N/A  $  $ 
               
Steven C. Boyd Cash Balance Plan(1)  15  $156,680  $ 
               
Mark Wienberg(2)
 N/A  N/A  $  $ 
               
Douglas T. Brinkworth Cash Balance Plan(1)  6  $98,920  $ 
27, 2014:

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    $256,392    $—    
  LTIP(3)   N/A    $658,436    $—    
  RUP(4)   N/A    $1,107,774    $—    

Michael A. Stivala (2)

  N/A   N/A    $—      $—    

Michael A. Kuglin (2)

  N/A   N/A    $—      $—    

Mark Wienberg (2)

  N/A   N/A    $—      $—    

Steven Boyd

  Cash Balance Plan (1)   15    $198,829    $—    

Douglas T. Brinkworth

  Cash Balance Plan (1)   6    $124,541    $—    

(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, Mr. Kuglin and Mr. Wienberg commenced employment with the Partnership after January 1, 2000, the date on which the Cash Balance Plan was closed to new participants, they do not participate in the Cash Balance Plan.
(3)Currently, Mr. Dunn is the only named executive officer who meets the retirement criteria of the LTIP. For such participants, upon retirement, outstanding but unvested awards under the LTIP awards become fully vested. However, payouts on those awards are deferred until the conclusion of each outstanding award’s three-year measurement period, based on the outcome of the TRU relative to the peer group.group for the 2012 award and the outcome of the distributable cash flow measurement for the 2014 award. The number reported on this line represents a projected payout of Mr. Dunn’s outstanding fiscal 20112014 and fiscal 2010 LTIP awards.2013 awards under the LTIP. Because the ultimate payout, if any, is predicated on the trading prices of the Partnership’s Common Units at the end of the three-year measurement period, as well as where within the peer group our TRU falls, the value reported may not be indicative of the value realized in the future upon vesting due to the variability in the trading price of our Common Units.
(4)Currently, Mr. Dunn is the only named executive officer who meets the retirement criteria of the RUP. Despite Mr. Dunn’s having met the plan’s retirement criteria, only his fiscal 2008 award is currently subject to the plan’s retirement provisions until December 3, 2010. For more information on this and the retirement provisions, refer to the subheading “Restricted Unit Plans” in the “Compensation Discussion and Analysis.” For participants who meet the retirement criteria, upon retirement, outstanding RUP awards vest six months and one day after retirement.
(5)At its November 9, 2010 meeting, the Committee terminated the SERP; on December 1, 2010, Mr. Dunn was paid his accrued benefit of $57,611.

75


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 24, 201127, 2014 termination date:

                 
          Involuntary  Involuntary 
          Termination  Termination 
          Without Cause  Without Cause 
          by the  by the 
          Partnership or  Partnership or 
          by the  by the 
          Executive for  Executive for 
          Good Reason  Good Reason 
          without a  with a Change 
          Change of  of Control 
Executive Payments and Benefits Upon Termination Death  Disability  Control Event  Event 
 
Michael J. Dunn, Jr.                
Cash Compensation(1) (2) (3) (4)
 $-0-  $-0-  $475,000  $1,425,000 
Accelerated Vesting of Fiscal 2011 and 2010 LTIP Awards(5)
  N/A   N/A   N/A   703,281 
Accelerated Vesting of Outstanding RUP Awards(6)
  N/A   1,546,724   N/A   1,965,069 
Medical Benefits(3)
  N/A   N/A   13,755   N/A 
Total
 $-0-  $1,546,724  $488,755  $4,093,350 
                 
Michael A. Stivala                
Cash Compensation(1) (2) (3) (4)
 $-0-  $-0-  $275,000  $742,500 
Accelerated Vesting of Fiscal 2011 and 2010 LTIP Awards(5)
  N/A   N/A   N/A   314,091 
Accelerated Vesting of Outstanding RUP Awards(6)
  N/A   663,858   N/A   914,865 
Medical Benefits(3)
  N/A   N/A   13,755   N/A 
Total
 $-0-  $663,858  $288,755  $1,971,456 
                 
Steven C. Boyd                
Cash Compensation(1) (2) (3) (4)
 $-0-  $-0-  $270,000  $729,000 
Accelerated Vesting of Fiscal 2011 and 2010 LTIP Awards(5)
  N/A   N/A   N/A   308,414 
Accelerated Vesting of Outstanding RUP Awards(6)
  N/A   599,398   N/A   850,405 
Medical Benefits(3)
  N/A   N/A   14,272   N/A 
Total
 $-0-  $599,398  $284,272  $1,887,819 
                 
Mark Wienberg                
Cash Compensation(1) (2) (3) (4)
 $-0-  $-0-  $250,000  $675,000 
Accelerated Vesting of Fiscal 2011 and 2010 LTIP Awards(5)
  N/A   N/A   N/A   274,964 
Accelerated Vesting of Outstanding RUP Awards(6)
  N/A   511,019   N/A   762,026 
Medical Benefits(3)
  N/A   N/A   13,755   N/A 
Total
 $-0-  $511,019  $263,755  $1,711,990 
                 
Douglas T. Brinkworth                
Cash Compensation(1) (2) (3) (4)
 $-0-  $-0-  $245,000  $661,500 
Accelerated Vesting of Fiscal 2011 and 2010 LTIP Awards(5)
  N/A   N/A   N/A   279,838 
Accelerated Vesting of Outstanding RUP Awards(6)
  N/A   540,155   N/A   791,162 
Medical Benefits(3)
  N/A   N/A   13,755   N/A 
Total
 $-0-  $540,155  $258,755  $1,732,500 
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.” As was indicated above in the “Compensation Discussion and Analysis,” concurrent with the beginning of fiscal 2015, Mr. Dunn’s retirement became effective; as such, in Mr. Dunn’s case, the numbers reported for him under the column heading “Involuntary Termination Without Cause by the Partnership or by the Executive for Good Reason without a Change of Control Event” reflect actual future payments that will be made to him in accordance with the letter agreement between him and the Partnership.

Executive Payments and Benefits Upon Termination

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

Michael J. Dunn, Jr.

        

Cash Compensation (1) (2) (3) (4) 

  $-0-    $990,000    $990,000    $1,485,000  

Accelerated Vesting of Fiscal 2014, 2013, and 2012 LTIP Awards (5)

   N/A     N/A     N/A     1,103,213  

Accelerated Vesting of Outstanding RUP Awards (6)

   1,107,774     1,107,774     1,107,774     1,107,774  

Medical Benefits (3)

   N/A     N/A     N/A     N/A  

Total

  $1,107,774    $2,097,774    $2,097,774    $3,695,987  

Michael A. Stivala

        

Cash Compensation (1) (2) (3) (4) 

  $-0-    $-0-    $425,000    $1,275,000  

Accelerated Vesting of Fiscal 2014, 2013, and 2012 LTIP Awards (5)

   N/A     N/A     N/A     527,025  

Accelerated Vesting of Outstanding RUP Awards (6)

   2,242,523     949,685     N/A     2,242,523  

Medical Benefits (3)

   N/A     N/A     18,853     N/A  

Total

  $2,242,523    $949,685    $443,853    $4,044,548  

Michael A. Kuglin

        

Cash Compensation (1) (2) (3) (4) 

  $-0-    $-0-    $265,000    $675,750  

Accelerated Vesting of Fiscal 2014, 2013, and 2012 LTIP Awards (5)

   N/A     N/A     N/A     340,110  

Accelerated Vesting of Outstanding RUP Awards (6)

   1,367,785     650,871     N/A     1,367,785  

Medical Benefits (3)

   N/A     N/A     16,917     N/A  

Total

  $1,367,785    $650,871    $281,917    $2,383,645  

Mark Wienberg

        

Cash Compensation (1) (2) (3) (4) 

  $-0-    $-0-    $325,000    $877,500  

Accelerated Vesting of Fiscal 2014, 2013, and 2012 LTIP Awards (5)

   N/A     N/A     N/A     487,838  

Accelerated Vesting of Outstanding RUP Awards (6)

   1,713,552     949,685     N/A     1,713,552  

Medical Benefits (3)

   N/A     N/A     19,008     N/A  

Total

  $1,713,552    $949,685    $344,008    $3,078,890  

Steven C. Boyd

        

Cash Compensation (1) (2) (3) (4) 

  $-0-    $-0-    $315,000    $850,500  

Accelerated Vesting of Fiscal 2014, 2013, and 2012 LTIP Awards (5)

   N/A     N/A     N/A     512,031  

Accelerated Vesting of Outstanding RUP Awards (6)

   1,713,552     949,685     N/A     1,713,552  

Medical Benefits(3)

   N/A     N/A     18,654     N/A  

Total

  $1,713,552    $949,685    $333,654    $3,076,083  

Douglas T. Brinkworth

        

Cash Compensation (1) (2) (3) (4) 

  $-0-    $-0-    $300,000    $810,000  

Accelerated Vesting of Fiscal 2014, 2013, and 2012 LTIP Awards (5)

   N/A     N/A     N/A     472,775  

Accelerated Vesting of Outstanding RUP Awards (6)

   1,713,552     949,685     N/A     1,713,552  

Medical Benefits (3)

   N/A     N/A     18,706     N/A  

Total

  $1,713,552    $949,685    $318,706    $2,996,327  

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

(2)In the event of disability, the named executive officer is entitled to a payment equal to his earned but unpaid salary and pro-rata cash bonus. Because the terms of our letter agreement with Mr. Dunn became effective on September 29, 2012, for purposes of this table it has been assumed that if Mr. Dunn became disabled on September 27, 2014, the provisions of our letter agreement would govern. For more information on Mr. Dunn’s letter agreement, refer to the subheading “Letter Agreement of Mr. Dunn” in the “Compensation Discussion and Analysis.”

(3)Any severance benefits, unrelated to a change of control event, payable to these officers would be determined by the Committee on a case-by-case basis in accordance with prior treatment of other similarly situated executives and may, as a result, differ from this hypothetical presentation. For purposes of this table, we have assumed that each of these named executive officers would, upon termination of employment without cause or for resignation for good reason, receive accrued salary and benefits through the date of termination plus one times annual salary and continued participation, at active employee rates, in the Partnership’sour health insurance plans for one year. The terms of our letter agreement with Mr. Dunn became effective on September 29, 2012; therefore, Mr. Dunn’s severance benefits for a termination of employment without cause or resignation for good reason have been calculated in accordance with this agreement. For more information on Mr. Dunn’s letter agreement, refer to the subheading “Letter Agreement of Mr. Dunn” in the “Compensation Discussion and Analysis.”

 

76


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

(5)In the event of a change of control, all awards under the LTIP awards will vest immediately regardless of whether termination immediately follows. If a change of control event occurs, the calculationpre-fiscal 2014 award payments will be equal to 125% of the cash value of a participant’s unvested LTIP paymentunits 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 the change of control occurred. The post-fiscal 2013 award payments will be made as if our total returnequal to Common Unitholders was higher than that provided by any150% of the other memberscash value of a participant’s unvested LTIP units plus a sum equal to 150% of a participant’s unvested LTIP units multiplied by an amount equal to the peer groupcumulative, per-Common Unit distribution from the beginning of an unvested award’s three-year measurement period through the date on which the change of control occurred If a change of control event occurred on September 27, 2014, the fiscal 2014, fiscal 2013, and fiscal 2012 awards would have been subject to their unitholders.this treatment. For more information, refer to the subheading “2003 Long-Term“Long-Term Incentive Plan” in the “Compensation Discussion and Analysis.”
In the event of death, the inability to continue employment due to permanent disability, or a termination without cause or a good reason resignation unconnected to a change of control event, awards will vest in accordance with the normal vesting schedule and will be subject to the same requirements as awards held by individuals still employed by the Partnership and will be subject to the same risks as awards held by all other participants.

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

(6)TheEffective November 13, 2012, the Committee amended the RUP document makes no provisionsto provide for the vesting of unvested awards held by recipients who die prior toa participant at the completiontime of the vesting schedule.his or her death. If a recipient of a RUP award becomes permanently disabled, only those awards that have been held for at least one year on the date that the employee’s employment is terminated as a result of his or her permanent disability will immediately vest; all awards held by the recipient for less than one year will be forfeited by the recipient. Because Mr. Dunn, Mr. Stivala, Mr. Boyd, Mr. Wienberg and Mr. Brinkworth each received a RUP award during fiscal 2011, ifIf any or all of the five named executive officers had become permanently disabled on September 24, 2011,28, 2013, the following quantities of unvested restricted units would have vested: Dunn, 33,497:25,009; Stivala, 14,377;21,440; Kuglin, 14,694; Wienberg, 21,440; Boyd, 12,981; Wienberg, 11,067;21,440; and Brinkworth, 11,698.21,440. The following quantities would have been forfeited: Stivala, 29,187; Kuglin, 16,185; Wienberg, 17,245; Boyd, 17,245; and Brinkworth, 17,245. Because all of Mr. Dunn’s unvested awards are subject to the plan’s retirement provisions, if Mr. Dunn 9,060; Stivala, 5,436; Boyd, 5,436; Wienberg, 5,436; Brinkworth, 5,436.
Under circumstances unrelated to a changebecame permanently disabled on the last day of control, if a RUP award recipient’s employment is terminated without cause or he or she resigns for good reason, any RUPthe fiscal year, none of his unvested awards held by such recipient will bewould have been forfeited.
In the event of a change of control, as defined in the RUP document, all unvested RUP awards will vest immediately on the date the change of control is consummated, regardless of the holding period and regardless of whether the recipient’s employment is terminated.

All of Mr. Dunn’s unvested awards are subject to the plan’s retirement provisions.

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

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

SUPERVISORS’ COMPENSATION

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

             
  Fees Earned       
  or Paid in       
  Cash  Unit Awards  Total 
Supervisor ($)(1)  ($)(2)  ($) 
             
John D. Collins $75,000  $0  $75,000 
Harold R. Logan, Jr.  100,000   0   100,000 
Dudley C. Mecum  75,000   0   75,000 
John Hoyt Stookey  75,000   0   75,000 
Jane Swift  75,000   0   75,000 
2014.

Supervisor

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

Harold R. Logan, Jr.

  $115,000     N/A    $115,000  

Lawrence C. Caldwell

  $85,000     N/A    $85,000  

Matthew J. Chanin

  $85,000     N/A    $85,000  

John D. Collins

  $85,000     N/A    $85,000  

Dudley C. Mecum

  $85,000     N/A    $85,000  

John Hoyt Stookey

  $85,000     N/A    $85,000  

Jane Swift

  $85,000     N/A    $85,000  

(1)This includes amounts earned for fiscal 2011,2014, including quarterly retainer installments for the fourth quarter of 20112014 that were paid in November 2011. Does2014. It does not include amounts paid in fiscal 20112014 for fiscal 20102013 quarterly retainer installments.
(2)Our SupervisorsDuring fiscal 2014, the Compensation Committee did not receive RUP awards made during this fiscal year. All previous awards were made in accordance withmake any additional grants of unvested restricted units to the provisionsmembers of our Restricted Unit Plans and vest accordingly.Board of Supervisors. As of September 24, 2011, each non-employee member of the Board of Supervisors held the following quantities of unvested restricted unit awards: Mr.27, 2014, Messrs. Logan, Collins, 6,348 units; Mr. Logan, 5,100 units; Mr. Mecum, 5,100 units; Mr. Stookey, 5,100 units; and Ms. Swift 6,348each held awards of 7,800 unvested restricted units and Messrs. Caldwell and Chanin each held awards of 6,023 unvested restricted units.
Note:The columns for reporting option awards, non-equity incentive plan compensation, changes in pension value and non-qualified deferred compensation plan earnings and all other forms of compensation were omitted from the Supervisor’s Compensation Table because the Partnership does not provide these forms of compensation to its non-employee supervisors.

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

77


Fees and Benefit Plans for Non-Employee Supervisors

Annual Cash Retainer Fees. As the Chairman of the Board of Supervisors, Mr. Logan receivesreceived an annual retainer of $100,000,$115,000 in fiscal 2014, payable in quarterly installments of $25,000$28,750 each. Each of the other non-employee Supervisors receivesreceived an annual cash retainer of $75,000,$85,000 in fiscal 2014, payable in quarterly installments of $18,750$21,250 each.

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

Restricted Unit Plans.Each non-employee Supervisor participates in the Restricted Unit Plans. All awards vest in accordance with the provisions of the plan document (see “Compensation Discussion and Analysis” section titled “Restricted Unit Plans” for a description of the vesting schedule). Upon vesting, all awards are settled by issuing Common Units. During fiscal 2004,As of September 27, 2014 Messrs. Logan, Collins, Mecum, and Stookey, were granted unvested restricted unit plan awards of 8,500 units each; during fiscal 2007, each of them received an additional unvested award of 3,000 units. Upon commencement of their terms as supervisors in fiscal 2007, Mr. Collins and Ms. Swift each receivedheld awards of 7,800 unvested restricted units and Messrs. Caldwell and Chanin each held awards of 6,023 unvested restricted units. At its November 11, 2014 meeting, the Compensation Committee established a policy of granting a retiring Supervisor an award of 5,496 units. During fiscal 2010, each non-employee Supervisor received a grant1,000 restricted units, in recognition of 3,600 units. Messrs. Logan,his or her services to the Partnership. Pursuant to this policy, the Compensation Committee granted Mr. Mecum, and Stookey arewho has informed the only non-employee Supervisors who have satisfiedBoard that he does not intend to run for re-election at the retirement provisionsnext Tri-Annual Meeting of the Partnership’s Restricted Unit Plans.

Unitholders (currently scheduled for Spring 2015), an award of 1,000 unvested restricted units.

Additional Supervisor Compensation.Non-employee Supervisors receive no other forms of remuneration from us. The only perquisite provided to the members of the Board of Supervisors is the ability to purchase propane at the same discounted rate that we offer propane to our employees, the value of which was less than $10,000 in fiscal 20112014 for each Supervisor.

78


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

The following table sets forth certain information as of November 23, 201124, 2014 regarding the beneficial ownership of Common Units by (a) each person or group known to the Partnership, based upon its review of filings under Section 13(d) or (g) under the Securities Act, to own more than 5% of the outstanding Common Units; (b) each member of the Board of Supervisors,Supervisors; (c) each executive officer named in the Summary Compensation Table in Item 11 of this Annual Report,Report; and (d) all members of the Board of Supervisors and executive officers as a group. Based upon filings under Section 13(d) or (g) under the Exchange Act, the Partnership does not know of any person or group who beneficially owns more than 5% of the outstanding Common Units. Except as set forth in the notes to the table, each individual or entity has sole voting and investment power over the Common Units reported.

         
  Amount and Nature of  Percent 
Name of Beneficial Owner Beneficial Ownership (1)  of Class 
Michael J. Dunn, Jr. (a)  73,715   * 
Michael A. Stivala (b)  11,784   * 
Steven C. Boyd (c)  17,861   * 
Mark Wienberg (d)  4,515   * 
Douglas T. Brinkworth (e)  21,068   * 
         
John Hoyt Stookey (f)  6,066   * 
Harold R. Logan, Jr.(f)  16,730   * 
Dudley C. Mecum (f)  15,634   * 
John D. Collins (g)  15,198   * 
Jane Swift (g)  1,374   * 
         
All Members of the Board of Supervisors and Executive Officers, as a Group (16 persons) (h)  244,382   1%

Name of Beneficial Owner

  Amount and
Nature of

Beneficial
Ownership (1)
   Percent of
Class (2)
 

Neuberger Berman Group LLC (a)

   7,080,982     11.7

Michael J. Dunn, Jr. (b)

   113,888     *  

Michael A. Stivala (c)

   22,319     *  

Michael A. Kuglin (d)

   5,084     *  

Mark Wienberg (e)

   8,275     *  

Steven C. Boyd (f)

   26,001     *  

Douglas T. Brinkworth (g)

   24,093     *  

John Hoyt Stookey (h)

   9,366     *  

Harold R. Logan, Jr.(h)

   10,240     *  

Jane Swift (h)

   -0-     *  

John D. Collins (h)

   17,246     *  

Dudley C. Mecum (i)

   18,934     *  

Lawrence C. Caldwell (j)

   15,963     *  

Matthew J. Chanin (k)

   5,000     *  

All Members of the Board of Supervisors and Executive Officers, as a Group (19 persons) (l)

   343,032     *  

(1)With the exception of the 7,080,982 units held by Neuberger Berman Group LLC (of which the Partnership has no knowledge, see note (a) below), the 784 units held by the General Partner (see (a)note (c) below) and the 10,092 units held by charitable organizations over which Mr. Caldwell has shared investment and voting power (see note (i) below), there is a possibility that any of the above listed units could be pledged as security.

(2)Based upon 60,457,780 Common Units outstanding on November 24, 2014.

*Less than 1%.

(a)Includes 784Based upon a Schedule 13G/A dated February 12, 2014 filed by Neuberger Berman Group LLC and Neuberger Berman LLC, which indicates that as of December 31, 2013 they had the shared power to vote or direct the vote of 6,774,935 Common Units held byand the General Partner,shared power to dispose or direct the disposition of which Mr. Dunn7,080,982 Common Units. The Schedule 13G indicates that Neuberger Berman Group LLC may be deemed to be a beneficial owner of these Common Units for purposes of Rule 13d-3 because certain affiliates have shared power to retain or dispose of Common Units belonging to many unrelated clients. We make no representation as to the accuracy or completeness of the information reported. The address of Neuberger Berman Group LLC is the sole member. 605 Third Avenue, New York NY 10158.

(b)Excludes 35,17325,009 unvested restricted units, none of which will vest in the 60-day period following November 23, 2011.24, 2014.
(b)(c)Includes 784 Common Units held by the General Partner, of which Mr. Stivala is the sole member. Excludes 18,04043,352 unvested restricted units, none of which will vest in the 60-day period following November 23, 2011.24, 2014.
(c)(d)Excludes 16,92225,795 unvested restricted units, none of which will vest in the 60-day period following November 23, 2011.24, 2014.
(d)(e)Excludes 15,70031,410 unvested restricted units, none of which will vest in the 60-day period following November 23, 2011.24, 2014.
(e)(f)Excludes 15,47931,410 unvested restricted units, none of which will vest in the 60-day period following November 23, 2011.24, 2014.
(f)(g)Excludes 5,10031,410 unvested restricted units, none of which will vest in the 60-day period following November 23, 2011.24, 2014.
(g)(h)Excludes 6,3487,800 unvested restricted units, none of which will vest in the 60-day period following November 23, 2011.24, 2014.
(h)(i)Inclusive of the units referred to in footnotes (a), (b), (c), (d), (e), (f) and (g) above, the reported number of units excludes 207,501Excludes 8,800 unvested restricted units, none of which will vest in the 60 day60-day period following November 23, 2011, owned24, 2014.
(j)Includes 10,092 Common Units held by certain executive officers, whosecharitable organizations over which Mr. Caldwell has shared investment and voting power. Excludes 6,023 unvested restricted units, none of which will vest onin the same basis as described60-day period following November 24, 2014.
(k)Excludes 6,023 unvested restricted units, none of which will vest in the 60-day period following November 24, 2014.
(l)Inclusive of the unvested restricted units referred to in footnotes (b), (c), (d), (e), (f), (g), (h), (i), (j) and (g) above.(k) above, the reported number of units excludes 361,882 unvested restricted units, none of which will vest in the 60-day period following November 24, 2014.

79


Securities Authorized for Issuance Under the Restricted Unit Plans

The following table sets forth certain information, as of September 24, 2011,27, 2014, with respect to the Partnership’s Restricted Unit Plans, under which restricted units of the Partnership, as described in the Notes to the Consolidated Financial Statements included in this Annual Report, are authorized for issuance.

             
          Number of restricted units 
          remaining available for 
  Number of Common      future issuance under the 
  Units to be issued upon  Weighted-average grant  Restricted Unit Plans (excluding 
  vesting of restricted  date fair value per  securities reflected in 
Plan units  restricted unit  column (a)) 
Category (a)  (b)  (c) 
Equity compensation plans approved by security holders (1)  485,423(2) $32.71   967,594 
Equity compensation plans not approved by security holders         
          
Total  485,423  $32.71   967,594 
          

Plan Category

  Number of Common
Units to be issued
upon
vesting of restricted
units
(a)
  Weighted-
average grant
date fair
value per
restricted
unit
(b)
   Number of restricted
units
remaining available for
future issuance under
the
Restricted Unit Plans
(excluding
securities reflected in
column (a))
(c)
 

Equity compensation plans approved by security holders (1)

   694,927(2)  $32.07     417,758  

Equity compensation plans not approved by security holders

   —      —       —    
  

 

 

  

 

 

   

 

 

 

Total

   694,927   $32.07     417,758  
  

 

 

  

 

 

   

 

 

 

(1)Relates to the Restricted Unit Plans.
(2)Represents number of restricted units that, as of September 24, 2011,27, 2014, had been granted under the Restricted Unit PlanPlans but had not yet vested.

80


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

Related Person Transactions

None.

Supervisor Independence

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

1.Within the past three years, the Supervisor:

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

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

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

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

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

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

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

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

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

81


ITEM 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES

The following table sets forth the aggregate fees for services related to fiscal years 20112014 and 20102013 provided by PricewaterhouseCoopers LLP, our independent registered public accounting firm.

         
  Fiscal  Fiscal 
  2011  2010 
         
Audit Fees (a) $1,956,000  $2,162,500 
Tax Fees (b)  686,425   728,223 
All Other Fees (c)  1,800   1,605 

   Fiscal
2014
   Fiscal
2013
 

Audit Fees (a)

  $2,440,000    $2,378,400  

Tax Fees (b)

   1,064,200     1,399,000  

All Other Fees (c)

   1,800     1,800  
  

 

 

   

 

 

 
  $3,506,000    $3,779,200  
  

 

 

   

 

 

 

(a)Audit Fees consist of professional services rendered for the integrated audit of our annual consolidated financial statements and our internal control over financial reporting, including reviews of our quarterly financial statements, as well as the issuance of consents in connection with other filings made with the SEC.
(b)Tax Fees consist of fees for professional services related to tax reporting, tax compliance and transaction services assistance.
(c)All Other Fees represent fees for the purchase of a license to an accounting research software tool.

The Audit Committee of the Board of Supervisors has adopted a formal policy concerning the approval of audit and non-audit services to be provided by the independent registered public accounting firm, PricewaterhouseCoopers LLP. The policy requires that all services PricewaterhouseCoopers LLP may provide to us, including audit services and permitted audit-related and non-audit services, be pre-approved by the Audit Committee. The Audit Committee pre-approved all audit and non-audit services provided by PricewaterhouseCoopers LLP during fiscal 20112014 and fiscal 2010.

2013.

82


PART IV
ITEM 15.EXHIBITS, FINANCIAL STATEMENT SCHEDULES

ITEM 15.EXHIBITS, FINANCIAL STATEMENT SCHEDULES

 (a)The following documents are filed as part of this Annual Report:

 1.Financial Statements
See “Index to Financial Statements” set forth on page F-1.

See “Index to Financial Statements” set forth on page F-1.

 2.Financial Statement Schedule
See “Index to Financial Statement Schedule” set forth on page S-1.

See “Index to Financial Statement Schedule” set forth on page S-1.

 3.Exhibits
See “Index to Exhibits” set forth on page E-1.

See “Index to Exhibits” set forth on page E-1.

83

SIGNATURES


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

  
 SUBURBAN PROPANE PARTNERS, L.P.
Date:    November 23, 201126, 2014    By: /s/ MICHAEL J. DUNN, JR.  A. STIVALA
 
  Michael J. Dunn, Jr. A. Stivala
 

President, Chief Executive Officer and

Supervisor

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

Signature

  

Title

  

Date

By:/s/ MICHAEL A. STIVALA

President, Chief Executive Officer

and Supervisor

November 26, 2014
(Michael A. Stivala)    
SignatureTitleDate
By: /s/ MICHAEL J. DUNN, JR.
(Michael J. Dunn, Jr.)
President, Chief Executive
Officer and Supervisor
November 23, 2011
By:/s/ HAROLD R. LOGAN, JR.
(Harold R. Logan, Jr.)
  Chairman and Supervisor  November 23, 201126, 2014
 (Harold R. Logan, Jr.)    
By: /s/ JOHN HOYT STOOKEY
SupervisorNovember 26, 2014
(John Hoyt Stookey)  SupervisorNovember 23, 2011
By: /s/ DUDLEY C. MECUM
SupervisorNovember 26, 2014
(Dudley C. Mecum)  SupervisorNovember 23, 2011
By: /s/ JOHN D. COLLINS
SupervisorNovember 26, 2014
(John D. Collins)  SupervisorNovember 23, 2011
By: /s/ JANE SWIFT
(Jane Swift)
  Supervisor  November 23, 201126, 2014
 (Jane Swift)    
By: /s/ MICHAEL A. STIVALA
(Michael A. Stivala)LAWRENCE C. CALDWELL
  Chief Financial OfficerSupervisor  November 23, 201126, 2014
 (Lawrence C. Caldwell)    
By/s/ MATTHEW J. CHANINSupervisorNovember 26, 2014
(Matthew J. Chanin)
By: /s/ MICHAEL A. KUGLIN

Chief Financial Officer and

Chief Accounting Officer

November 26, 2014
(Michael A. Kuglin)  Vice President and
Chief Accounting Officer
By: /s/ DANIEL S. BLOOMSTEINControllerNovember 23, 201126, 2014
(Daniel S. Bloomstein)

84


INDEX TO EXHIBITS

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

Exhibit
Number

  

Description

    2.1  Contribution Agreement dated as of April 25, 2012, as amended as of June 15, 2012, July 6, 2012 and July 19, 2012, among Inergy, L.P., Inergy GP, LLC, Inergy Sales and Service, Inc. and Suburban Propane Partners, L.P. (Incorporated by reference to Exhibit 2.1 to the Partnership’s Current Reports on Form 8-K filed April 26, 2012, June 15, 2012, July 6, 2012 and July 19, 2012, respectively).
Exhibit
NumberDescription
    
3.1  Third Amended and Restated Agreement of Limited Partnership of the Partnership dated as of October 19, 2006, as amended as of July 31, 2007. (Incorporated by reference to Exhibit 3.1 to the Partnership’s Current Report on Form 8-K filed August 2, 2007).
    3.2  Third Amended and Restated Agreement of Limited Partnership of the Operating Partnership dated as of October 19, 2006, as amended as of June 24, 2009. (Incorporated by reference to Exhibit 10.2 to the Partnership’s Current Report on Form 8-K filed June 30, 2009).
    3.3  Amended and Restated Certificate of Limited Partnership of Suburban Propane Partners, L.P.the Partnership dated May 26, 1999 (Incorporated by reference to Exhibit 3.2 to the Partnership’s Quarterly Report on Form 10-Q filed August 6, 2009).
    3.4  Amended and Restated Certificate of Limited Partnership of Suburban Partners, L.P.the Operating Partnership dated May 26, 1999 (Incorporated by reference to Exhibit 3.3 to the Partnership’s Quarterly Report on Form 10-Q filed August 6, 2009).
    4.1  Description of Common Units of the Partnership. (Incorporated by reference to Exhibit 4.1 to the Partnership’s Current Report on Form 8-K filed October 19, 2006).
    4.44.2  Indenture, dated as of March 23, 2010, related to the 7.375% Senior Notes due 2020, by and among Suburban Propane Partners, L.P., Suburban Energy Finance CorporationCorp. and The Bank of New York Mellon, as Trustee, including the form of 7.375% Senior Notes due 2020. (Incorporated by reference to Exhibit 4.1 to the Partnership’s Current Report on Form 8-K filed March 23, 2010).
    4.54.3  First Supplemental Indenture, dated as of March 23, 2010, related to the 7.375% Senior Notes due 2020, by and among Suburban Propane Partners, L.P., Suburban Energy Finance CorporationCorp. and The Bank of New York Mellon, as Trustee. (Incorporated by reference to Exhibit 4.2 to the Partnership’s Current Report on Form 8-K filed March 23, 2010).
    4.4  Indenture, dated as of August 1, 2012, related to the 7.5% Senior Notes due 2018 and the 7.375% Senior Notes due 2021, by and among Suburban Propane Partners, L.P., Suburban Energy Finance Corp. and The Bank of New York Mellon, as Trustee, including the form of 7.5% Senior Notes due 2018 and the form of 7.375% Senior Notes due 2021. (Incorporated by reference to Exhibit 4.1 to the Partnership’s Current Report on Form 8-K filed August 2, 2012).
    4.5  First Supplemental Indenture, dated as of May 23, 2014, related to the 7.5% Senior Notes due 2018 and the 7.375% Senior Notes due 2021, by and among Suburban Propane Partners, L.P., Suburban Energy Finance Corp. and The Bank of New York Mellon, as Trustee. (Incorporated by reference to Exhibit 4.1 to the Partnership’s Current Report on Form 8-K filed May 27, 2014).

    10.14.6  Indenture, dated as of May 27, 2014, relating to the 5.50 % Senior Notes due 2024, among Suburban Propane Partners, L.P., Suburban Energy Finance Corp. and The Bank of New York Mellon, as Trustee, including the form of 5.50 % Senior Notes due 2024. (Incorporated by reference to Exhibit 4.1 to the Partnership’s Current Report on Form 8-K filed May 28, 2014).
    4.7First Supplemental Indenture, dated as of May 27, 2014, relating to the 5.50 % Senior Notes due 2024, among Suburban Propane Partners, L.P., Suburban Energy Finance Corp. and The Bank of New York Mellon, as Trustee. (Incorporated by reference to Exhibit 4.1 to the Partnership’s Current Report on Form 8-K filed May 28, 2014).
    4.8Support Agreement, dated as of August 1, 2012, among Inergy, L.P., the Partnership and Suburban Energy Finance Corp. (Incorporated by reference to Exhibit 4.3 to the Partnership’s Registration Statement on Form S-4 dated September 19, 2012).
  10.1  Agreement between Michael J. Dunn, Jr. and the Partnership, effective as of September 27, 2009. (Incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed November 10, 2009).
  10.2  Suburban Propane Partners, L.P. 2000 Restricted Unit Plan, as amended and restated effective October 17, 2006 and as further amended on July 31, 2007, October 31, 2007, January 24, 2008, January 20, 2009, November 10, 2009 and November 10, 2009.13, 2012. (Incorporated by reference to Exhibit 10.699.1 to the Partnership’s AnnualCurrent Report on Form 10-K for the fiscal year ended September 26, 2009)8-K filed November 14, 2012).
  10.3  Suburban Propane Partners, L.P. 2009 Restricted Unit Plan, effective August 1, 2009.2009, as amended on November 13, 2012 and August 6, 2013. (Incorporated by reference to Exhibit 99.199.2 to the Partnership’s Registration StatementCurrent Report on Form S-88-K filed on July 24, 2009)August 7, 2013).

E-1


Exhibit
NumberDescription
  
10.4  Suburban Propane, L.P. Severance Protection Plan, as amended on January 24, 2008, January 20, 2009 and November 10, 2009. (Incorporated by reference to Exhibit 10.8 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 26, 2009).
  10.5  Suburban Propane L.P. 2003 Long Term Incentive Plan, as amended on October 17, 2006 and as further amended on July 31, 2007, October 31, 2007, January 24, 2008 and January 20, 2009. (Incorporated by reference to Exhibit 10.3 to the Partnership’s Quarterly Report on Form 10-Q for the fiscal quarter ended December 27, 2008).
  10.6  Suburban Propane, L.P. 2013 Long Term Incentive Plan. (Incorporated by reference to Exhibit 99.1 to the Partnership’s Current Report on Form 8-K filed November 10, 2011).
  10.7  Suburban Propane, L.P. 2014 Long Term Incentive Plan. (Incorporated by reference to Exhibit 99.1 to the Partnership’s Current Report on Form 8-K filed August 7, 2013).
  10.610.8  Amended and Restated Retirement Savings and Investment Plan of Suburban Propane effective as of January 1, 1998). (Incorporated by reference to Exhibit 10.24 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 29, 2001).
  10.710.9  Amendment No. 1 to the Retirement Savings and Investment Plan of Suburban Propane (effective January 1, 2002). (Incorporated by reference to Exhibit 10.25 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 28, 2002).
  10.10  
10.8Amended and Restated Credit Agreement, among the Operating Partnership, the Partnership and Bank of America, N.A., as Administrative Agent and the Lenders party thereto, dated June 26, 2009.January 5, 2012. (Incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed on June 30, 2009)January 6, 2012).

  
10.910.11  First Amendment to the Amended and Restated Credit Agreement, dated March 9, 2010, by and among Suburban Propane, L.P., Suburban Propane Partners, L.P., each lender signatory theretothe Operating Partnership, the Partnership and Bank of America, N.A., as Administrative Agent, and the administrative agent for the lenders therein.Lenders party thereto, dated August 1, 2012. (Incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed on March 9, 2010)August 2, 2012).
  10.12  
10.10Non-CompetitionSecond Amendment to the Amended and Restated Credit Agreement, among the Operating Partnership, the Partnership and Bank of America, N.A., as Administrative Agent, and the Lenders party thereto, dated September 17, 2007, between Suburban Propane, L.P. and Plains LPG Services, L.P.May 9, 2014. (Incorporated by reference to Exhibit 10.210.1 to the Partnership’s Current Report on Form 8-K filed September 20, 2007)on May 12, 2014).
  10.1110.13  Propane Storage Agreement, dated September 17, 2007, between Suburban Propane, L.P. and Plains LPG Services, L.P. (Incorporated by reference to Exhibit 10.3 to the Partnership’s Current Report on Form 8-K filed September 20, 2007).
  21.1  Subsidiaries of Suburban Propane Partners, L.P. (Filed herewith).
  23.1  Consent of PricewaterhouseCoopers LLP. (Filed herewith).
  31.1  Certification of the President and Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. (Filed herewith).
  31.2  Certification of the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. (Filed herewith).
  32.1  Certification of the President and Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (Filed herewith).
  32.2  Certification of the Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (Filed herewith).
  99.1  Equity Holding Policy for Supervisors and Executives of Suburban Propane Partners, L.P. (Incorporated by reference to Exhibit 99.1 to the Partnership’s Current Report on Form 8-K dated May 10, 2010).

E-2


  99.2  Five-Year Performance Graph (Filed herewith).
Exhibit
NumberDescription
101.INS  XBRL Instance Document (Furnished herewith). *
101.SCH  XBRL Taxonomy Extension Schema Document (Furnished herewith). *
101.CAL  XBRL Taxonomy Extension Calculation Linkbase Document (Furnished herewith). *
101.DEF  XBRL Taxonomy Extension Definition Linkbase Document (Furnished herewith). *
101.LAB  XBRL Taxonomy Extension Label Linkbase Document (Furnished herewith). *
101.PRE  XBRL Taxonomy Extension Presentation Linkbase Document (Furnished herewith).*
*XBRL (Extensible Business Reporting Language) information is furnished and not filed or a part of a registration or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934 and otherwise is not subject to liability under these actions.

E-3



Report of Independent Registered Public Accounting Firm

To the Board of Supervisors and Unitholders of

Suburban Propane Partners, L.P.

:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of partners’ capital, comprehensive income and of cash flows present fairly, in all material respects, the financial position of Suburban Propane Partners, L.P.L.P and its subsidiaries at September 24, 201127, 2014 and September 25, 2010,28, 2013, and the results of their operations and their cash flows for each of the three fiscal years in the period ended September 24, 201127, 2014 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of September 24, 2011,27, 2014, based on criteria established inInternal Control — Control—Integrated Framework (1992)issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership’s management is responsible for these financial statements, and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing in Item 9A. Our responsibility is to express opinions on these financial statements on the financial statement schedule, and on the Partnership’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Florham Park, New Jersey

November 23, 2011

26, 2014

F-2


SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

         
  September 24,  September 25, 
  2011  2010 
 
ASSETS
        
Current assets:        
Cash and cash equivalents $149,553  $156,908 
Accounts receivable, less allowance for doubtful accounts of $6,960 and $5,403, respectively  66,630   60,383 
Inventories  65,907   61,047 
Other current assets  15,732   18,089 
       
Total current assets  297,822   296,427 
Property, plant and equipment, net  338,125   350,420 
Goodwill  277,651   277,244 
Other assets  42,861   46,823 
       
Total assets $956,459  $970,914 
       
         
LIABILITIES AND PARTNERS’ CAPITAL
        
Current liabilities:        
Accounts payable $37,456  $39,886 
Accrued employment and benefit costs  22,951   28,624 
Accrued insurance  9,950   10,480 
Customer deposits and advances  57,476   63,579 
Other current liabilities  23,681   21,945 
       
Total current liabilities  151,514   164,514 
Long-term borrowings  348,169   347,953 
Accrued insurance  42,891   44,965 
Other liabilities  55,667   50,826 
       
Total liabilities  598,241   608,258 
       
         
Commitments and contingencies        
         
Partners’ capital:        
Common Unitholders (35,429 and 35,318 units issued and outstanding at September 24, 2011 and September 25, 2010, respectively)  418,134   419,882 
Accumulated other comprehensive loss  (59,916)  (57,226)
       
Total partners’ capital  358,218   362,656 
       
Total liabilities and partners’ capital $956,459  $970,914 
       

   September 27,
2014
  September 28,
2013
 

ASSETS

   

Current assets:

   

Cash and cash equivalents

  $92,639   $107,232  

Accounts receivable, less allowance for doubtful accounts of $11,122 and $6,786, respectively

   96,915    94,854  

Inventories

   90,965    77,623  

Other current assets

   14,346    13,613  
  

 

 

  

 

 

 

Total current assets

   294,865    293,322  

Property, plant and equipment, net

   826,826    888,232  

Goodwill

   1,087,429    1,087,429  

Other intangible assets, net

   359,293    416,771  

Other assets

   40,950    42,233  
  

 

 

  

 

 

 

Total assets

  $2,609,363   $2,727,987  
  

 

 

  

 

 

 

LIABILITIES AND PARTNERS’ CAPITAL

   

Current liabilities:

   

Accounts payable

  $49,253   $52,766  

Accrued employment and benefit costs

   24,033    23,559  

Accrued insurance

   10,040    6,650  

Customer deposits and advances

   107,386    107,562  

Accrued interest

   16,313    24,357  

Other current liabilities

   15,241    19,000  
  

 

 

  

 

 

 

Total current liabilities

   222,266    233,894  

Long-term borrowings

   1,242,685    1,245,237  

Accrued insurance

   52,410    51,502  

Other liabilities

   70,549    68,228  
  

 

 

  

 

 

 

Total liabilities

   1,587,910    1,598,861  
  

 

 

  

 

 

 

Commitments and contingencies

   

Partners’ capital:

   

Common Unitholders (60,317 and 60,231 units issued and outstanding at September 27, 2014 and September 28, 2013, respectively)

   1,067,358    1,176,479  

Accumulated other comprehensive loss

   (45,905  (47,353
  

 

 

  

 

 

 

Total partners’ capital

   1,021,453    1,129,126  
  

 

 

  

 

 

 

Total liabilities and partners’ capital

  $2,609,363   $2,727,987  
  

 

 

  

 

 

 

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

F-3


SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit amounts)

             
  Year Ended 
  September 24,  September 25,  September 26, 
  2011  2010  2009 
Revenues            
Propane $929,492  $885,459  $864,012 
Fuel oil and refined fuels  139,572   135,059   159,596 
Natural gas and electricity  84,721   77,587   76,832 
All other  36,767   38,589   42,714 
          
   1,190,552   1,136,694   1,143,154 
Costs and expenses            
Cost of products sold  678,719   598,451   540,385 
Operating  279,329   289,567   304,767 
General and administrative  51,648   61,656   57,044 
Severance charge  2,000       
Pension settlement charge     2,818    
Depreciation and amortization  35,628   30,834   30,343 
          
   1,047,324   983,326   932,539 
          
             
Operating income  143,228   153,368   210,615 
Loss on debt extinguishment     (9,473)  (4,624)
Interest income  16   61   802 
Interest expense  (27,394)  (27,458)  (39,069)
          
             
Income before provision for income taxes  115,850   116,498   167,724 
Provision for income taxes  884   1,182   2,486 
          
             
Net income $114,966  $115,316  $165,238 
          
             
Income per Common Unit — basic $3.24  $3.26  $4.99 
          
Weighted average number of Common Units outstanding — basic  35,525   35,374   33,134 
          
             
Income per Common Unit — diluted $3.22  $3.24  $4.96 
          
Weighted average number of Common Units outstanding — diluted  35,723   35,613   33,315 
          

   Year Ended 
   September 27,
2014
  September 28,
2013
  September 29,
2012
 

Revenues

    

Propane

  $1,606,840   $1,357,102   $843,648  

Fuel oil and refined fuels

   194,684    208,957    114,288  

Natural gas and electricity

   87,093    79,432    67,419  

All other

   49,640    58,115    38,103  
  

 

 

  

 

 

  

 

 

 
   1,938,257    1,703,606    1,063,458  

Costs and expenses

    

Cost of products sold

   1,080,750    861,905    599,059  

Operating

   466,389    469,496    298,772  

General and administrative

   64,593    64,845    59,020  

Acquisition-related costs

   —      —      17,916  

Depreciation and amortization

   136,399    130,384    47,034  
  

 

 

  

 

 

  

 

 

 
   1,748,131    1,526,630    1,021,801  
  

 

 

  

 

 

  

 

 

 

Operating income

   190,126    176,976    41,657  

Loss on debt extinguishment

   (11,589  (2,144  (2,249

Interest expense

   (83,261  (95,427  (38,633
  

 

 

  

 

 

  

 

 

 

Income before provision for income taxes

   95,276    79,405    775  

Provision for income taxes

   767    607    137  
  

 

 

  

 

 

  

 

 

 

Net income

  $94,509   $78,798   $638  
  

 

 

  

 

 

  

 

 

 

Income per Common Unit - basic

  $1.56   $1.35   $0.02  
  

 

 

  

 

 

  

 

 

 

Weighted average number of Common Units outstanding - basic

   60,481    58,378    38,848  
  

 

 

  

 

 

  

 

 

 

Income per Common Unit - diluted

  $1.56   $1.34   $0.02  
  

 

 

  

 

 

  

 

 

 

Weighted average number of Common Units outstanding - diluted

   60,751    58,600    38,990  
  

 

 

  

 

 

  

 

 

 

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

F-4


SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWSCOMPREHENSIVE INCOME

(in thousands)

             
  Year Ended 
  September 24,  September 25,  September 26, 
  2011  2010  2009 
Cash flows from operating activities:            
Net income $114,966  $115,316  $165,238 
Adjustments to reconcile net income to net cash provided by operations:            
Depreciation and amortization expense  35,628   30,834   30,343 
Pension settlement charge     2,818    
Loss on debt extinguishment     9,473   4,624 
Deferred tax provision        1,385 
Other, net  3,316   6,120   3,895 
Changes in assets and liabilities:            
(Increase) decrease in accounts receivable  (6,247)  (7,709)  42,898 
(Increase) decrease in inventories  (4,721)  9,555   9,664 
Increase (decrease) in accounts payable  (2,134)  3,376   (22,402)
Increase (decrease) in accrued employment and benefit costs  (5,673)  (12,251)  13,822 
Increase (decrease) in accrued insurance  (2,604)  3,127   (20,785)
Increase (decrease) in customer deposits and advances  (6,103)  (6,328)  (5,437)
(Increase) decrease in other current and noncurrent assets  2,470   1,479   19,121 
Increase (decrease) in other current and noncurrent liabilities  3,888   (13)  4,185 
          
Net cash provided by operating activities  132,786   155,797   246,551 
          
Cash flows from investing activities:            
Capital expenditures  (22,284)  (19,131)  (21,837)
Acquisitions of businesses  (3,195)  (14,500)   
Proceeds from sale of property, plant and equipment  5,974   3,520   4,985 
          
Net cash (used in) investing activities  (19,505)  (30,111)  (16,852)
          
Cash flows from financing activities:            
Repayments of long-term borrowings     (256,510)  (177,821)
Proceeds from long-term borrowings     247,840   100,000 
Issuance costs associated with long-term borrowings     (5,018)  (5,543)
Repayments of short-term borrowings        (110,000)
Net proceeds from issuance of Common Units        95,880 
Partnership distributions  (120,636)  (118,263)  (106,740)
          
Net cash (used in) financing activities  (120,636)  (131,951)  (204,224)
          
Net (decrease) increase in cash and cash equivalents  (7,355)  (6,265)  25,475 
Cash and cash equivalents at beginning of year  156,908   163,173   137,698 
          
Cash and cash equivalents at end of year $149,553  $156,908  $163,173 
          
             
Supplemental disclosure of cash flow information:            
Cash paid for interest $24,584  $28,362  $39,153 
          

   Year Ended 
   September 27,
2014
  September 28,
2013
   September 29,
2012
 

Net income

  $94,509   $78,798    $638  

Other comprehensive income:

     

Net unrealized (losses) gains on cash flow hedges

   (518  584     (3,561

Reclassification of realized losses on cash flow hedges into earnings

   1,406    2,465     2,680  

Amortization of net actuarial losses and prior service credits into earnings and net change in funded status of benefit plans

   560    10,705     (310
  

 

 

  

 

 

   

 

 

 

Other comprehensive income (loss)

   1,448    13,754     (1,191
  

 

 

  

 

 

   

 

 

 

Total comprehensive income (loss)

  $95,957   $92,552    $(553
  

 

 

  

 

 

   

 

 

 

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

F-5


SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITALCASH FLOWS

(in thousands)

                     
          Accumulated       
          Other       
  Number of      Compre-  Total    
  Common  Common  hensive  Partners’  Comprehensive 
  Units  Unitholders  (Loss) Income  Capital  Income (Loss) 
                     
Balance at September 27, 2008  32,725  $262,050  $(44,155) $217,895     
                     
Net income      165,238       165,238  $165,238 
Other comprehensive income:                    
Net unrealized losses on cash flow hedges          (4,079)  (4,079)  (4,079)
Reclassification of realized losses on cash flow hedges into earnings          3,088   3,088   3,088 
Amortization of net actuarial losses and prior service credits into earnings and net change in funded status of benefit plans          (16,142)  (16,142)  (16,142)
                    
Total comprehensive income                 $148,105 
                    
Partnership distributions      (106,740)      (106,740)    
Common Units issued under Restricted Unit Plans  72                 
Sale of Common Units under public offering, net of offering expenses  2,431   95,880       95,880     
Compensation cost recognized under Restricted Unit Plans, net of forfeitures      2,396       2,396     
                 
Balance at September 26, 2009  35,228  $418,824  $(61,288) $357,536     
                     
Net income      115,316       115,316  $115,316 
Other comprehensive income:                    
Net unrealized losses on cash flow hedges          (5,706)  (5,706)  (5,706)
Reclassification of realized losses on cash flow hedges into earnings          3,597   3,597   3,597 
Amortization of net actuarial losses and prior service credits into earnings and net change in funded status of benefit plans          3,353   3,353   3,353 
Recognition in earnings of net actuarial loss for pension settlement          2,818   2,818   2,818 
                    
Total comprehensive income                 $119,378 
                    
Partnership distributions      (118,263)      (118,263)    
Common Units issued under Restricted Unit Plans  90                 
Compensation cost recognized under Restricted Unit Plans, net of forfeitures      4,005       4,005     
                 
Balance at September 25, 2010  35,318  $419,882  $(57,226) $362,656     
                     
Net income      114,966       114,966  $114,966 
Other comprehensive income:                    
Net unrealized losses on cash flow hedges          (1,177)  (1,177)  (1,177)
Reclassification of realized losses on cash flow hedges into earnings          2,881   2,881   2,881 
Amortization of net actuarial losses and prior service credits into earnings and net change in funded status of benefit plans          (4,394)  (4,394)  (4,394)
                    
Total comprehensive income                 $112,276 
                    
Partnership distributions      (120,636)      (120,636)    
Common Units issued under Restricted Unit Plans  111                 
Compensation cost recognized under Restricted Unit Plans, net of forfeitures      3,922       3,922     
                 
Balance at September 24, 2011  35,429  $418,134  $(59,916) $358,218     
                 

   Year Ended 
   September 27,
2014
  September 28,
2013
  September 29,
2012
 

Cash flows from operating activities:

    

Net income

  $94,509   $78,798   $638  

Adjustments to reconcile net income to net cash provided by operations:

    

Depreciation and amortization expense

   136,399    130,384    47,034  

Loss on debt extinguishment

   11,589    2,144    2,249  

Other, net

   5,664    (2,796  6,424  

Changes in assets and liabilities:

    

(Increase) decrease in accounts receivable

   (2,061  (5,910  13,762  

(Increase) decrease in inventories

   (13,342  10,553    8,189  

Increase (decrease) in accounts payable

   (3,513  (375  15,669  

Increase (decrease) in accrued employment and benefit costs

   474    7,045    (8,586

Increase (decrease) in accrued insurance

   4,298    3,601    (4,451

Increase (decrease) in customer deposits and advances

   (176  (16,735  18,352  

(Increase) decrease in other current and noncurrent assets

   266    5,436    (754

Increase (decrease) in other current and noncurrent liabilities

   (8,556  2,161    12,447  
  

 

 

  

 

 

  

 

 

 

Net cash provided by operating activities

   225,551    214,306    110,973  
  

 

 

  

 

 

  

 

 

 

Cash flows from investing activities:

    

Capital expenditures

   (30,052  (27,823  (17,476

Acquisitions of businesses, net of cash acquired

   —      —      (223,731

Proceeds from sale of property, plant and equipment

   13,520    7,310    1,449  

Adjustment to purchase price for Inergy Propane

   —      5,850    —    
  

 

 

  

 

 

  

 

 

 

Net cash (used in) investing activities

   (16,532  (14,663  (239,758
  

 

 

  

 

 

  

 

 

 

Cash flows from financing activities:

    

Proceeds from long-term borrowings

   525,000    —      100,000  

Repayments of long-term borrowings (includes premium and fees)

   (528,077  (168,915  (100,000

Proceeds from borrowings under revolving credit facility

   61,700    —      —    

Repayment of borrowings under revolving credit facility

   (61,700  —      —    

Proceeds from short-term borrowings

   —      —      225,000  

Repayments of short-term borrowings

   —      —      (225,000

Debt issuance costs

   (9,515  —      (25,199

Net proceeds from issuance of Common Units

   —      143,444    259,842  

Partnership distributions

   (211,020  (201,257  (121,094
  

 

 

  

 

 

  

 

 

 

Net cash (used in) provided by financing activities

   (223,612  (226,728  113,549  
  

 

 

  

 

 

  

 

 

 

Net (decrease) in cash and cash equivalents

   (14,593  (27,085  (15,236

Cash and cash equivalents at beginning of year

   107,232    134,317    149,553  
  

 

 

  

 

 

  

 

 

 

Cash and cash equivalents at end of year

  $92,639   $107,232   $134,317  
  

 

 

  

 

 

  

 

 

 

Supplemental disclosure of cash flow information:

    

Cash paid for interest

  $91,836   $86,583   $38,294  

Supplemental disclosure of non-cash investing and financing activities for the Inergy Propane Acquisition (see Note 3):

    

Issuance of long-term debt

  $—     $—     $1,075,043  

Issuance of equity

  $—     $—     $590,027  

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

F-6


SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(in thousands)

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

Balance at September 24, 2011

   35,429    $418,134   $(59,916 $358,218  

Net income

     638     638  

Net unrealized losses on cash flow hedges

      (3,561  (3,561

Reclassification of realized losses on cash flow hedges into earnings

      2,680    2,680  

Amortization of net actuarial losses and prior service credits into earnings and net change in funded status of benefit plans

      (310  (310

Partnership distributions

     (121,094   (121,094

Issuance of Common Units for business acquisition

   14,200     590,027     590,027  

Sale of Common Units under public offering, net of offering expenses

   7,245     259,842     259,842  

Common Units issued under Restricted Unit Plans

   139      

Compensation cost recognized under Restricted Unit Plans, net of forfeitures

     4,059     4,059  
  

 

 

   

 

 

  

 

 

  

 

 

 

Balance at September 29, 2012

   57,013    $1,151,606   $(61,107 $1,090,499  

Net income

     78,798     78,798  

Net unrealized gains on cash flow hedges

      584    584  

Reclassification of realized losses on cash flow hedges into earnings

      2,465    2,465  

Amortization of net actuarial losses and prior service credits into earnings and net change in funded status of benefit plans

      10,705    10,705  

Partnership distributions

     (201,257   (201,257

Sale of Common Units under public offering, net of offering expenses

   3,105     143,444     143,444  

Common Units issued under Restricted Unit Plans

   113      

Compensation cost recognized under

      

Restricted Unit Plans, net of forfeitures

     3,888     3,888  
  

 

 

   

 

 

  

 

 

  

 

 

 

Balance at September 28, 2013

   60,231    $1,176,479   $(47,353 $1,129,126  

Net income

     94,509     94,509  

Net unrealized losses on cash flow hedges

      (518  (518

Reclassification of realized losses on cash flow hedges into earnings

      1,406    1,406  

Amortization of net actuarial losses and prior service credits into earnings and net change in funded status of benefit plans

      560    560  

Partnership distributions

     (211,020   (211,020

Common Units issued under Restricted Unit Plans

   86      

Compensation cost recognized under Restricted Unit Plans, net of forfeitures

     7,390     7,390  
  

 

 

   

 

 

  

 

 

  

 

 

 

Balance at September 27, 2014

   60,317    $1,067,358   $(45,905 $1,021,453  
  

 

 

   

 

 

  

 

 

  

 

 

 

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

SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(dollars in thousands, except unit and per unit amounts)

1. Partnership Organization and Formation

Suburban Propane Partners, L.P. (the “Partnership”) is a publicly traded Delaware limited partnership principally engaged, through its operating partnership and subsidiaries, in the retail marketing and distribution of propane, fuel oil and refined fuels, as well as the marketing of natural gas and electricity in deregulated markets. In addition, to complement its core marketing and distribution businesses, the Partnership services a wide variety of home comfort equipment, particularly for heating and ventilation. The publicly traded limited partner interests in the Partnership are evidenced by common units traded on the New York Stock Exchange (“Common Units”), with 35,428,85560,316,746 Common Units outstanding at September 24, 2011.27, 2014. The holders of Common Units are entitled to participate in distributions and exercise the rights and privileges available to limited partners under the Third Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”), adopted on October 19, 2006 following approval by Common Unitholders at the Partnership’s Tri-Annual Meeting and as thereafter amended by the Board of Supervisors on July 31, 2007, pursuant to the authority granted to the Board in the Partnership Agreement.amended. Rights and privileges under the Partnership Agreement include, among other things, the election of all members of the Board of Supervisors and voting on the removal of the general partner.

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

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

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

Suburban Energy Finance Corporation,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.

On August 1, 2012 (the “Acquisition Date”), the Partnership completed the acquisition of the sole membership interest in Inergy Propane, LLC, including certain wholly-owned subsidiaries of Inergy Propane LLC, and the assets of Inergy Sales and Service, Inc. The acquired interests and assets are collectively referred to as “Inergy Propane.” As of the Acquisition Date, Inergy Propane consisted of the former retail propane assets and operations of Inergy, L.P. (“Inergy”). On the Acquisition Date, Inergy Propane and its remaining wholly-owned subsidiaries acquired became subsidiaries of the Operating Partnership, 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.

The Partnership serves approximately 750,0001.2 million residential, commercial, industrial and agricultural customers from approximately 300710 locations in 3041 states. The Partnership’s operations are principally concentrated in the east and west coast regions, of the United States, including Alaska. No single customer accounted for 10% or more of the Partnership’s revenues during fiscal 2011, 20102014, 2013 or 2009.

2012.

2. Summary of Significant Accounting Policies

Principles of Consolidation.The consolidated financial statements include the accounts of the Partnership, the Operating Partnership and all of its direct and indirect subsidiaries. All significant intercompany transactions and account balances have been eliminated. The Partnership consolidates the results of operations, financial condition and cash flows of the Operating Partnership as a result of the Partnership’s 100% limited partner interest in the Operating Partnership.

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Fiscal Period.The Partnership uses a 52/53 week fiscal year which ends on the last Saturday in September. The Partnership’s fiscal quarters are generally 13 weeks in duration. When the Partnership’s fiscal year is 53 weeks long, the corresponding fourth quarter is 14 weeks in duration.
Fiscal 2014 and fiscal 2013 included 52 weeks of operations and fiscal 2012 included 53 weeks of operations.

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

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

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

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

Level 1: Quoted prices in active markets for identical assets or liabilities.
Level 2: Quoted prices in active markets for similar assets or liabilities; quoted prices for identical or similar instruments in markets that are not active; and model-derived valuations in which all significant inputs are observable in active markets.
Level 3: Valuations derived from valuation techniques in which one or more significant inputs are unobservable.

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

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

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

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

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

Derivative Instruments and Hedging Activities.

Commodity Price Risk.Given the retail nature of its operations, the Partnership maintains a certain level of priced physical inventory to help ensure its field operations have adequate supply commensurate with the time of year. The Partnership’s strategy is to keep its physical inventory priced relatively close to market for its field operations. The Partnership enters into a combination of exchange-traded futures and option contracts and, in certain instances, over-the-counter optionoptions and swap contracts (collectively, “derivative instruments”) to hedge price risk associated with propane and fuel oil physical inventories, as well as future purchases of propane or fuel oil used in its operations and to help ensure adequate supply during periods of high demand. In addition, the Partnership sells propane and fuel oil to customers at fixed prices, and enters into derivative instruments to hedge a portion of its exposure to fluctuations in commodity prices as a result of selling the fixed price contracts. Under this risk management strategy, realized gains or losses on derivative instruments will typically offset losses or gains on the physical inventory once the product is sold.sold or delivered as it pertains to fixed price contracts. All of the Partnership’s derivative instruments are reported on the consolidated balance sheet at their fair values. In addition, in the course of normal operations, the Partnership routinely enters into contracts such as forward priced physical contracts for the purchase or sale of propane and fuel oil that qualify for and are designated as normal purchase or normal sale contracts. Such contracts are exempted from the fair value accounting requirements and are accounted for at the time product is purchased or sold under the related contract. The Partnership does not use derivative instruments for speculative trading purposes. Market risks associated with futures, options and forward contractsderivative instruments are monitored daily for compliance with the Partnership’s Hedging and Risk Management Policy which includes volume limits for open positions. Priced on-hand inventory is also reviewed and managed daily as to exposures to changing market prices.

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

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

F-9

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


Long-Lived Assets.

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

Buildings  40 Years
Building and land improvements  20-4020 Years
Transportation equipment  3-20 Years
Storage facilities  7-40 Years
Office equipment  5-10 Years
Tanks and cylinders  15-4010-40 Years
Computer software  3-7 Years

The weighted average estimated useful life of the Partnership’s storage facilities and tanks and cylinders is approximately 27 years.

21 years and 28 years, respectively.

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

Goodwill.Goodwill represents the excess of the purchase price over the fair value of net assets acquired. Goodwill is subject to an impairment review at a reporting unit level, on an annual basis in Augustas of the end of fiscal July of each year, or when an event occurs or circumstances change that would indicate potential impairment.

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

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

Other Intangible Assets.Other intangible assets consist of customer lists,relationships, tradenames, non-compete agreements and leasehold interests. Customer listsrelationships and tradenames are amortized under the straight-line method over the estimated period for which the assets are expected to contribute to the future cash flows of the reporting entities to which they relate, ending periodically between fiscal years 20122016 and 2021. Non-compete agreements are amortized under the straight-line method over the periods of the related agreements. Leasehold interests are amortized under the straight-line method over the shorter of the lease term or the useful life of the related assets, through fiscal 2025.

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

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

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

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

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

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

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

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

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

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

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

Net Income Per Unit.Computations of basic income per Common Unit are performed by dividing net income by the weighted average number of outstanding Common Units, and vested (and unissued) restricted units granted under the Partnership’s Restricted Unit Plans, as defined below, to retirement-eligible grantees. Computations of diluted income per Common Unit are performed by dividing net income by the weighted average number of outstanding Common Units and unissued restricted units granted under the Restricted Unit Plans. In computing diluted net income per Common Unit, weighted average units outstanding used to compute basic net income per Common Unit were increased by 198,298, 238,589269,867, 222,419 and 180,789141,570 units for fiscal 2011, 20102014, 2013 and 2009,2012, respectively, to reflect the potential dilutive effect of the unvested restricted units outstanding using the treasury stock method.

Comprehensive Income.The Partnership reports comprehensive (loss) income (the total of net income and all other non-owner changes in partners’ capital) within the consolidated statement of partners’ capital. Comprehensive (loss)comprehensive income. Other comprehensive income includes unrealized gains and losses on derivative instruments accounted for as cash flow hedges and reclassifications of realized losses on cash flow hedges into earnings, amortization of net actuarial losses and prior service credits into earnings and changes in the funded status of pension and other postretirement benefit plans.

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

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Recently Issued Accounting Pronouncements.In May 2011,2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09 “Revenue from Contracts with Customers” (“ASU 2014-09”). This update provides a principles-based approach to revenue recognition, requiring revenue recognition to depict the transfer of goods or services to customers in an accountingamount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The ASU provides a five-step model to be applied to all contracts with customers. The five steps are to identify the contract(s) with the customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract and recognize revenue when each performance obligation is satisfied. The revenue standard update to provide guidance on achieving a consistent definition of and common requirements for fair value measurement and related disclosure requirements in US GAAP. The new guidance requires quantitative information about unobservable inputs, valuation processes and sensitivity analysis associated with fair value measurements categorized within Level 3 of the fair value hierarchy, and is effective prospectively duringfor the first interim andperiod within annual reporting periods beginning after December 15, 2011,2016, which will be the secondPartnership’s first quarter of fiscal year 2018. ASU 2014-09 can be applied either retrospectively to each prior reporting period presented or retrospectively with the Partnership’s 2012 fiscal year. Earlycumulative effect of initially applying the update recognized at the date of the initial application along with additional disclosures. The Partnership is evaluating the impacts, if any, the adoption is not permitted. No material impact is expectedof ASU 2014-09 will have on the Partnership’s consolidatedresults of operations, financial position or cash flows.

Recently Adopted Accounting Pronouncements. In December 2011, the FASB issued an 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 amendment, further clarified with ASU 2013-01, enhances 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 Partnership adopted ASU 2011-11 and ASU 2013-01 on September 29, 2013 and included further disclosure regarding offsetting assets and liabilities for derivative instruments accounted for under ASC 815. As this guidance affects disclosures only, its adoption had no impact on the Partnership’s financial position, results of operations andor cash flows.

In June 2011,February 2013, the FASB issued an accounting standard updateASU to provide guidance on increasingestablish the prominence of items reported in other comprehensive income. This update eliminateseffective date for the optionrequirement to present components of reclassifications out of accumulated other comprehensive income as parteither parenthetically on the face of the statement of partners’ capital and requires that the total of comprehensive income, the components of net income and the components of other comprehensive income be presented either in a single continuous statement of comprehensive incomefinancial statements or in two separate but consecutive statements. Earlythe notes to the financial statements (“ASU 2013-02”). The Partnership adopted ASU 2013-02 on September 29, 2013 and its adoption of this updated guidance is permitted, and it becomes effective retrospectively during interim and annual periods beginning after December 15, 2011, which will be the second quarter of the Partnership’s 2012 fiscal year. This update doesdid not change the items that must be reported in other comprehensive income.

In September 2011, the FASB issued a revised accounting standard allowing companies to first assess qualitative factors to determine whetherincome, nor did it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If, as a result of the qualitative assessment, it is more likely than not that the fair value of a reporting unit is less than its carrying amount, a more detailed two-step goodwill impairment test would be performed to identify a potential goodwill impairment and measure the amount of loss to be recognized, if any. The standard will be effective for annual and interim goodwill impairment tests performed after December 31, 2011, with early adoption permitted. The adoption of this standard is not expected tohave an impact on the Partnership’s financial position, results of operations or cash flows.
Subsequent Events.

3. Acquisition of Inergy Propane

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

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

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

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

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

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

The table provides the final purchase price allocation:

Assets acquired:

  

Cash and cash equivalents

  $7,964  

Accounts receivable

   36,076  

Inventories

   30,457  

Other current assets

   2,067  
  

 

 

 

Current assets acquired

   76,564  

Property, plant & equipment

   617,854  

Customer relationships (estimated useful life of 9 years)

   445,500  

Non-compete agreements (estimated useful life of 6 years)

   23,059  

Other intangible assets (estimated useful life of 4 years)

   1,983  

Goodwill

   809,778  

Other assets

   2,151  
  

 

 

 

Total assets acquired

  $1,976,889  
  

 

 

 

Liabilities assumed:

  

Accounts payable

  $16  

Accrued employment and benefit costs

   2,149  

Customer deposits and advances

   48,469  

Other current liabilities

   18,613  

Other noncurrent liabilities

   16,727  
  

 

 

 

Total liabilities assumed

   85,974  
  

 

 

 

Total

  $1,890,915  
  

 

 

 

The final purchase price allocation resulted in the following adjustments to the provisional fair value estimates: property, plant and equipment decreased $33,302, intangible assets (principally customer relationships) increased $39,583, other current assets decreased $765 and other noncurrent liabilities increased $646. The net effect of these adjustments resulted in a $4,870 decrease to goodwill as of the Acquisition Date. As a result, results of operations for fiscal 2012 have been revised for a $205 decrease to depreciation expense and a $1,449 increase to amortization expense.

The following presents unaudited pro forma combined financial information as if the Inergy Propane Acquisition had occurred on September 25, 2011, the first day of the Partnership’s 2012 fiscal year, as adjusted for the final purchase price allocation. The unaudited pro forma combined financial information was prepared under the assumption that the net proceeds from the issuance of the 6,300,000 Common Units on August 14, 2012 were used to fund the portion of the Inergy Propane Acquisition that was originally financed through the 364-Day Facility (which was repaid two weeks after the balance sheet date throughAcquisition Date). As a result, the Common Units were assumed to have been issued on September 30, 2011, and, in turn, the pro forma results for the fiscal year ended September 29, 2012 do not include any interest costs associated with the 364-Day Facility.

   Year Ended
September 29,
2012
 

Revenues

  $1,842,698  

Net income

  $12,824  

Income per common unit

  

Basic

  $0.23  

Diluted

  $0.23  

The unaudited pro forma combined financial information is not necessarily indicative of the results that would have occurred had the Inergy Propane Acquisition occurred on the date its financial statements were issued, and concluded there were no events or transactions occurring during this period that required recognition or disclosure in its financial statements.

3.indicated nor is it necessarily indicative of future operating results.

4. Distributions of Available Cash

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

The following summarizes the quarterly distributions per Common Unit declared and paid in respect of each of the quarters in the three fiscal years in the period ended September 24, 2011:

             
  Fiscal  Fiscal  Fiscal 
  2011  2010  2009 
             
First Quarter $0.8525  $0.8350  $0.8100 
Second Quarter  0.8525   0.8400   0.8150 
Third Quarter  0.8525   0.8450   0.8250 
Fourth Quarter  0.8525   0.8500   0.8300 
27, 2014:

 

   Fiscal
2014
   Fiscal
2013
   Fiscal
2012
 

First Quarter

  $0.8750    $0.8750    $0.8525  

Second Quarter

   0.8750     0.8750     0.8525  

Third Quarter

   0.8750     0.8750     0.8525  

Fourth Quarter

   0.8750     0.8750     0.8525  

F-13


4.5. Selected Balance Sheet Information

Inventories consist of the following:

         
  As of 
  September 24,  September 25, 
  2011  2010 
         
Propane, fuel oil and refined fuels and natural gas $64,601  $59,836 
Appliances and related parts  1,306   1,211 
       
  $65,907  $61,047 
       

   As of 
   September 27,
2014
   September 28,
2013
 

Propane, fuel oil and refined fuels and natural gas

  $89,470    $75,885  

Appliances

   1,495     1,738  
  

 

 

   

 

 

 
  $90,965    $77,623  
  

 

 

   

 

 

 

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

Property, plant and equipment consist of the following:

         
  As of 
  September 24,  September 25, 
  2011  2010 
         
Land and improvements $27,904  $28,250 
Buildings and improvements  82,639   80,072 
Transportation equipment  19,067   22,959 
Storage facilities  79,525   78,176 
Equipment, primarily tanks and cylinders  485,859   481,423 
Computer systems  47,718   44,705 
Construction in progress  2,704   5,290 
       
   745,416   740,875 
Less: accumulated depreciation  407,291   390,455 
       
  $338,125  $350,420 
       

   As of 
   September 27,
2014
  September 28,
2013
 

Land and improvements

  $201,353   $207,516  

Buildings and improvements

   103,751    104,137  

Transportation equipment

   64,254    71,815  

Storage facilities

   110,586    113,571  

Equipment, primarily tanks and cylinders

   823,478    830,282  

Computer systems

   49,904    49,049  

Construction in progress

   3,420    4,472  
  

 

 

  

 

 

 
   1,356,746    1,380,842  

Less: accumulated depreciation

   (529,920  (492,610
  

 

 

  

 

 

 
  $826,826   $888,232  
  

 

 

  

 

 

 

Depreciation expense for the fiscal 2011, 20102014, 2013 and 20092012 amounted to $32,368, $28,411$78,921, $72,353 and $28,123,$35,032, respectively. During fiscal 2011 and fiscal 2010, the Partnership recorded a $2,883 and $1,800 adjustment, respectively, to accelerate depreciation expense on certain assets taken out of service.

5.

6. Goodwill and Other Intangible Assets

The Partnership’s fiscal 20112014 and fiscal 20102013 annual goodwill impairment review resulted in no adjustments to the carrying amount of goodwill. During fiscal 2009, the Partnership reversed $1,385 of the deferred tax asset valuation allowance, respectively, which was established through purchase accounting, as a reduction to goodwill. This adjustment resulted from the utilization of a portion of the net operating losses established in purchase accounting. As a result of the adoption of revised accounting guidance concerning business combinations at the beginning of fiscal 2010, future reversals of the deferred tax asset valuation allowance will be reflected as a reduction of income tax expense.

F-14


The changes in carrying valuevalues of goodwill assigned to the Partnership’s operating segments are as follows:
                 
      Fuel oil and  Natural gas    
  Propane  refined fuels  and electricity  Total 
Balance as of September 25, 2010                
Goodwill $264,906  $10,900  $7,900  $283,706 
Accumulated adjustments     (6,462)     (6,462)
             
  $264,906  $4,438  $7,900  $277,244 
             
                 
Balance as of September 24, 2011                
Goodwill $265,313  $10,900  $7,900  $284,113 
Accumulated adjustments     (6,462)     (6,462)
             
  $265,313  $4,438  $7,900  $277,651 
             
                 
Goodwill acquired during fiscal 2011 $407  $  $  $407 

   Propane   Fuel oil
and
refined
fuels
  Natural
gas and
electricity
   Total 

Balance as of September 27, 2014 and September 28, 2013

       

Goodwill

  $1,075,091    $10,900   $7,900    $1,093,891  

Accumulated adjustments

   —       (6,462  —       (6,462
  

 

 

   

 

 

  

 

 

   

 

 

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

 

 

   

 

 

  

 

 

   

 

 

 

Other intangible assets consist of the following:

         
  As of 
  September 24,  September 25, 
  2011  2010 
         
Customer lists $26,523  $25,761 
Non-compete agreements  3,756   3,156 
Tradenames  1,499   1,499 
Other  1,967   1,967 
       
   33,745   32,383 
       
Less: accumulated amortization        
Customer lists  (15,036)  (12,671)
Non-compete agreements  (760)  (107)
Tradenames  (1,162)  (1,012)
Other  (709)  (617)
       
   (17,667)  (14,407)
       
  $16,078  $17,976 
       

   As of 
   September 27,
2014
  September 28,
2013
 

Customer relationships

  $466,959   $466,959  

Non-compete agreements

   26,815    26,815  

Tradenames

   3,482    3,482  

Other

   1,967    1,967  
  

 

 

  

 

 

 
   499,223    499,223  
  

 

 

  

 

 

 

Less: accumulated amortization

   

Customer relationships

   (122,411  (71,382

Non-compete agreements

   (13,962  (8,138

Tradenames

   (2,573  (2,040

Other

   (984  (892
  

 

 

  

 

 

 
   (139,930  (82,452
  

 

 

  

 

 

 
  $359,293   $416,771  
  

 

 

  

 

 

 

Aggregate amortization expense related to other intangible assets for fiscal 2011, 20102014, 2013 and 20092012 was $3,260, $2,423$57,478, $58,031 and $2,220,$12,002, respectively. Aggregate amortization expense for each of the five succeeding fiscal years related to other intangible assets held as of September 24, 201127, 2014 is as follows: 2012 — $2,834; 2013 — $2,676; 2014 — $2,341; 2015 — $2,180- $56,767; 2016 - $53,971; 2017 - $52,686; 2018 - $52,326; and 2016 — $1,690.

6.2019 - $51,303.

7. Income Taxes

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

F-15


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

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

             
  Year Ended 
  September 24,  September 25,  September 26, 
  2011  2010  2009 
 
Current            
Federal $135  $177  $173 
State and local  749   1,005   928 
          
   884   1,182   1,101 
 
Deferred        1,385 
          
  $884  $1,182  $2,486 
          

   Year Ended 
   September 27,
2014
   September 28,
2013
   September 29,
2012
 

Current

      

Federal

  $10    $26    $18  

State and local

   757     581     119  
  

 

 

   

 

 

   

 

 

 
   767     607     137  

Deferred

   —       —       —    
  

 

 

   

 

 

   

 

 

 
  $767    $607    $137  
  

 

 

   

 

 

   

 

 

 

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

             
  Year Ended 
  September 24,  September 25,  September 26, 
  2011  2010  2009 
             
Income tax provision at federal statutory tax rate $40,548  $40,361  $58,704 
Impact of Partnership income not subject to federal income taxes  (39,952)  (38,808)  (56,294)
Permanent differences  239   2,051   719 
Change in valuation allowance  (454)  (4,806)  (2,048)
State income taxes  492   2,247   1,262 
Other  11   137   143 
          
Provision for income taxes — current and deferred $884  $1,182  $2,486 
          

 

F-16

   Year Ended 
   September 27,
2014
  September 28,
2013
  September 29,
2012
 

Income tax provision at federal statutory tax rate

  $33,346   $27,792   $271  

Impact of Partnership income not subject to federal income taxes

   (38,919  (35,187  (4,564

Permanent differences

   86    71    244  

Transfer of assets to Corporate Entities

   —      —      8,181  

Change in valuation allowance

   5,458    9,771    (3,567

State income taxes

   (60  (1,135  339  

Other

   856    (705  (767
  

 

 

  

 

 

  

 

 

 

Provision for income taxes—current

  $767   $607   $137  
  

 

 

  

 

 

  

 

 

 


The components of net deferred taxes and the related valuation allowance using currently enacted tax rates are as follows:
         
  As of 
  September 24,  September 25, 
  2011  2010 
Deferred tax assets:        
Net operating loss carryforwards $32,938  $33,214 
Allowance for doubtful accounts  1,323   713 
Inventory  658   1,423 
Intangible assets  1,201   1,362 
Deferred revenue  1,303   1,408 
Derivative instruments  71   700 
AMT credit carryforward  1,086   925 
Other accruals  1,936   1,726 
       
Total deferred tax assets  40,516   41,471 
       
Deferred tax liabilities:        
Property, plant and equipment  314   815 
       
Total deferred tax liabilities  314   815 
       
Net deferred tax assets  40,202   40,656 
Valuation allowance  (40,202)  (40,656)
       
Net deferred tax assets $  $ 
       
7.

   As of 
   September 27,
2014
  September 28,
2013
 

Deferred tax assets:

   

Net operating loss carryforwards

  $51,321   $46,356  

Allowance for doubtful accounts

   1,371    878  

Inventory

   433    525  

Intangible assets

   122    577  

Deferred revenue

   1,524    2,188  

Derivative instruments

   71    109  

AMT credit carryforward

   1,086    1,086  

Other accruals

   2,060    2,062  
  

 

 

  

 

 

 

Total deferred tax assets

   57,988    53,781  
  

 

 

  

 

 

 

Deferred tax liabilities:

   

Property, plant and equipment

   6,124    7,375  
  

 

 

  

 

 

 

Total deferred tax liabilities

   6,124    7,375  
  

 

 

  

 

 

 

Net deferred tax assets

   51,864    46,406  

Valuation allowance

   (51,864  (46,406
  

 

 

  

 

 

 

Net deferred tax assets

  $—     $—    
  

 

 

  

 

 

 

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

8. Long-Term Borrowings

Long-term borrowings consist of the following:

         
  As of 
  September 24,  September 25, 
  2011  2010 
7.375% senior notes, due March 15, 2020, net of unamortized discount of $1,831 and $2,047, respectively $248,169  $247,953 
Revolving Credit Agreement, due June 25, 2013  100,000   100,000 
       
  $348,169  $347,953 
       

   As of 
   September 27,
2014
   September 28,
2013
 

7.5% senior notes, due October 1, 2018, including unamortized premium of $-0- and $28,614, respectively

  $—      $525,171  

7.375% senior notes, due March 15, 2020, net of unamortized discount of $1,183 and $1,400, respectively

   248,817     248,600  

7.375% senior notes, due August 1, 2021, including unamortized premium of $22,688 and $25,286, respectively

   368,868     371,466  

5.5% senior notes, due June 1, 2024

   525,000     —    

Revolving Credit Facility, due January 5, 2017

   100,000     100,000  
  

 

 

   

 

 

 
  $1,242,685    $1,245,237  
  

 

 

   

 

 

 

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 $496,557 in aggregate principal amount of unregistered 7.5% senior notes due October 1, 2018 (the “2018 Senior Notes”) and $503,443 in aggregate principal amount of unregistered 7.375% senior notes due August 1, 2021 (the “2021 Senior Notes”) in a private placement in connection with the Inergy Propane Acquisition described in Note 3. Based on market rates for similar issues, the 2018 Senior Notes and 2021 Senior Notes were valued at 106.875% and 108.125%, respectively, of the principal amount, on the Acquisition Date as they were issued in exchange for Inergy’s outstanding notes, not for cash.

On May 27, 2014, the Partnership repurchased and satisfied and discharged all of its 2018 Senior Notes with net proceeds from the issuance of the 2024 Senior Notes, as defined below, and cash on hand pursuant to a tender offer and redemption during the third quarter of fiscal 2014. In connection with this tender offer and redemption, the Partnership recognized a loss on the extinguishment of debt of $11,589 consisting of $31,633 for the redemption premium and related fees, as well as the write-off of $5,230 and ($25,274) in unamortized debt origination costs and unamortized premium, respectively. The 2018 Senior Notes required semi-annual interest payments in April and October, and the 2021 Senior Notes require semi-annual interest payments in February and August.

The 2021 Senior Notes are redeemable, at the Partnership’s option, in whole or in part, at any time on or 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, the Partnership completed an offer to exchange its then-outstanding unregistered 7.5% senior notes due 2018 and 7.375% senior notes due 2021 (collectively, the “Old Notes”) for an equal principal amount of 7.5% senior notes due 2018 and 7.375% senior notes due 2021 (collectively, the “Exchange Notes”), respectively, that have been registered under the Securities Act of 1933, as amended. The terms of the Exchange Notes are identical in all material respects (including principal amount, interest rate, maturity and redemption rights) to the Old Notes for which they were exchanged, except that the Exchange Notes generally will not be subject to transfer restrictions.

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

2020 Senior Notes

On March 23, 2010, the Partnership and its 100%-owned subsidiary, Suburban Energy Finance Corporation,Corp., completed a public offering of $250,000 in aggregate principal amount of 7.375% senior notes due March 15, 2020 (the “2020 Senior Notes”). The 2020 Senior Notes were issued at 99.136% of the principal amount.amount and require semi-annual interest payments in March and September.

The 2020 Senior Notes are redeemable, at the Partnership’s option, in whole or in part, at any time on or 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

   102.458

2017

   101.229

2018 and thereafter

   100.000

2024 Senior Notes

As previously discussed, on May 27, 2014, the Partnership and its 100%-owned subsidiary, Suburban Energy Finance Corp., completed a public offering of $525,000 in aggregate principal amount of 5.5% senior notes due June 1, 2024 (the “2024 Senior Notes”). The 2024 Senior Notes were issued at 100% of the principal amount and require semi-annual interest payments in June and December, beginning in December 2014. The net proceeds from the issuance of the 2024 Senior Notes, along with cash on hand, were used to repurchase the 6.875% senior notes due in 2013 (the “2013 Senior Notes”) on March 23, 2010 through a redemption and tender offer. In connection with the repurchasesatisfy and discharge all of the 20132018 Senior Notes.

The 2024 Senior Notes are redeemable, at the Partnership recognized a lossPartnership’s option, in whole or in part, at any time on or after June 1, 2019, in each case at the extinguishmentredemption prices described in the table below, together with any accrued and unpaid interest to the date of debt of $9,473 in fiscal 2010, consisting of $7,231 for the repurchase premium and related fees, as well as the write-off of $2,242 in unamortized debt origination costs and unamortized discount.

redemption.

Year

  Percentage 

2019

   102.750

2020

   101.833

2021

   100.917

2022 and thereafter

   100.000

The Partnership’s obligations under the 2020 Senior Notes, 2021 Senior Notes and 2024 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 2020 Senior Notes are structurally subordinated to, which means they rank effectively behind, any debt and other liabilities of the Operating Partnership. The 2020 Senior Notes mature on March 15, 2020 and require semi-annual interest payments in March and September. The Partnership is permitted to redeem some or all of the 2020 Senior Notes any time at redemption prices specified in the indenture governing the 2020 Senior Notes. In addition, the 2020 Senior Noteseach have a change of control provision that would require the Partnership to offer to repurchase the notes at 101% of the principal amount repurchased, if a change of control, as defined in the indenture, occurs and is followed by a rating decline (a decrease in the rating of the notes by either Moody’s Investors Service or Standard and Poor’s Rating Group by one or more gradations) within 90 days of the consummation of the change of control.

F-17

Credit Agreement


On June 26, 2009, theThe Operating Partnership executedhas an amended and restated credit agreement entered into on January 5, 2012, as amended on August 1, 2012 and May 9, 2014 (collectively, the “Amended Credit Agreement”) that provides for a Credit Agreement (the “Credit Agreement”) to provide a four-year $250,000five-year $400,000 revolving credit facility (the “Revolving Credit Facility”). The Credit Agreement replaced the Operating Partnership’s previous credit facility, which provided for a $108,000 term loan (the “Term Loan”) and a separate $175,000 working capital facility both, of which $100,000 was outstanding as amended, were scheduled to mature in March 2010.of September 27, 2014 and September 28, 2013. Borrowings under the Revolving Credit Facility may be used for general corporate purposes, including working capital, capital expenditures and acquisitions until maturity on June 25, 2013.acquisitions. The Operating Partnership has the right to prepay any borrowings under the Revolving Credit Facility, in whole or in part, without penalty at any time prior to maturity. At closing,

During the second quarter of fiscal 2014, the Partnership experienced a significant increase in working capital requirements as a result of the significant increase in wholesale propane costs. The increase in working capital resulted in the net borrowing of $55,000 under the Partnership’s Revolving Credit Facility in the second quarter of fiscal 2014. These additional borrowings were repaid in full in April 2014 with internally generated cash.

The amendment and restatement of the credit agreement on January 5, 2012 amended the previous credit agreement to, among other things, extend the maturity date from June 25, 2013 to January 5, 2017, reduce the borrowing rate and commitment fees, and amend certain affirmative and negative covenants.

On August 1, 2012, the Operating Partnership borrowed $100,000executed an amendment to the Amended Credit Agreement to, among other things, provide for (i) a $250,000 senior secured 364-Day Facility and (ii) an increase in our revolving credit facility under the Amended Credit Agreement from $250,000 to $400,000. On the Acquisition Date, the Operating Partnership drew $225,000 on the 364-Day Facility, which was used to fund a portion of the Inergy Propane Acquisition, including costs and expenses related to the acquisition. The Partnership repaid the $225,000 of borrowings under the 364-Day Facility on August 14, 2012 with the net proceeds from the public issuance of Common Units on August 14, 2012.

The amendment to the Amended Credit Agreement on August 1, 2012 also amended certain restrictive and affirmative covenants applicable to the Operating Partnership and the Partnership, as well as certain financial covenants, including (a) requiring the Partnership’s consolidated interest coverage ratio, as defined in the amendment, to be not less than 2.0 to 1.0 as of the end of any fiscal quarter; (b) prohibiting the total consolidated leverage ratio, as defined in the amendment, of the Partnership from being greater than 7.0 to 1.0 as of the end of any fiscal quarter. The minimum consolidated interest coverage ratio increases over time, and commencing with the second quarter of fiscal 2014, such minimum ratio is 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 is 4.75 to 1.0 (or 5.0 to 1.0 during an acquisition period as defined in the amendment).

On May 9, 2014, the Operating Partnership executed a second amendment to the Amended Credit Agreement to make certain technical amendments with respect to agreements relating to debt refinancing.

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

Borrowings under the Revolving Credit Facility and, along with cash on hand, repaidof the $108,000 then outstanding under the Term Loan and terminated the previous credit facility. In addition, the Partnership has standby letters of credit issued under the RevolvingAmended Credit Facility in the aggregate amount of $54,856 primarily in support of retention levels under its self-insurance programs, which expire periodically through April 15, 2012. Therefore, as of September 24, 2011 the Partnership had available borrowing capacity of $95,144 under the Revolving Credit Facility.

Borrowings under the Revolving Credit FacilityAgreement bear interest at prevailing interest rates based upon, at the Operating Partnership’s option, LIBOR plus the applicable margin or the base rate, defined as the higher of the Federal Funds Rate plus1/2 of 1%, the agent bank’s prime rate, or LIBOR plus 1%, plus in each case the applicable margin. The applicable margin is dependent upon the Partnership’s ratio of total debt to EBITDA on a consolidated basis, as defined in the Revolving Credit Facility. As of September 24, 2011,27, 2014, the interest rate for the Revolving Credit Facility was approximately 3.25%2.5%. The interest rate and the applicable margin will be reset at the end of each calendar quarter.
The Partnership acts as a guarantor

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

On July 31, 2009, the Operating Partnership entered into an interest rate swap agreement with a notional amount of $100,000, an effective date of March 31, 2010June 25, 2013 and a termination date of June 25, 2013.January 5, 2017. Under thethis interest rate swap agreement, the Operating Partnership will pay a fixed interest rate of 3.12%1.63% to the issuing lender on the notional principal amount outstanding, effectively fixing the LIBOR portion of the interest rate at 3.12%. In return,and the issuing lender will pay to the Operating Partnership a floating rate, namely LIBOR, on the same notional principal amount. ThisThe interest rate swap agreement replaced the previous interest rate swap agreement which terminated on March 31, 2010. The interest rate swaps havehas been designated as a cash flow hedge.
The

As of September 27, 2014, the Partnership had standby letters of credit issued under the Revolving Credit Facility in the aggregate amount of $44,882 which expire periodically through April 3, 2015. Therefore, as of September 27, 2014 the Partnership had available borrowing capacity of $255,118 under the Revolving Credit Facility.

The Amended Credit Agreement and the 2020 Senior Notes both contain various restrictive and affirmative covenants applicable to the Operating Partnership and the Partnership, respectively, including (i) restrictions on the incurrence of additional indebtedness, and (ii) restrictions on certain liens, investments, guarantees, loans, advances, payments, mergers, consolidations, distributions, sales of assets and other transactions. The Revolving Credit Facility contains certain financial covenants (a) requiring the Partnership’s consolidated interest coverage ratio, as defined, to be not less than 2.5 to 1.0 as of the end of any fiscal quarter; (b) prohibiting the total consolidated leverage ratio, as defined, of the Partnership from being greater than 4.5 to 1.0 as of the end of any fiscal quarter; and (c) prohibiting the Operating Partnership’s senior secured consolidated leverage ratio, as defined, from being greater than 3.0 to 1.0 as of the end of any fiscal quarter. Under the indentureAmended Credit Agreement and the indentures governing the 2020 Senior Notes, the Operating Partnership isand the Partnership are generally permitted to make cash distributions equal to available cash, as defined, as of the end of the immediately preceding quarter, if no event of default exists or would exist upon making such distributions, and with respect to the indentures governing the Senior Notes, the Partnership’s consolidated fixed charge coverage ratio, as defined, is greater than 1.75 to 1. The Partnership and the Operating Partnership were in compliance with all covenants and terms of the 2020 Senior Notes and the RevolvingAmended Credit FacilityAgreement as of September 24, 2011.

27, 2014.

F-18


Debt origination costs representing the costs incurred in connection with the placement of, and the subsequent amendment to, long-term borrowings are capitalized within other assets and amortized on a straight-line basis over the term of the respective debt agreements. During fiscal 2014, the Partnership recognized charges of $5,230 to write-off unamortized debt origination costs associated with the tender offer and redemption of its 2018 Senior Notes. During fiscal 2013, the Partnership recognized charges of $2,064 million to write-off unamortized debt origination costs associated with the repurchase of its 2021 Senior Notes. Other assets at September 24, 201127, 2014 and September 25, 201028, 2013 include debt origination costs with a net carrying amount of $7,207$21,023 and $9,157,$21,254, respectively.

The aggregate amounts of long-term debt maturities subsequent to September 24, 201127, 2014 are as follows: 2012:fiscal 2015 through fiscal 2016: $-0-; 2013:fiscal 2017: $100,000; 2014:fiscal 2018: $-0-; 2015:fiscal 2019: $-0-; and thereafter: $250,000.

8.$1,121,180.

9. Unit-Based Compensation Arrangements

As described in Note 2, the Partnership recognizes compensation cost over the respective service period for employee services received in exchange for an award of equity, or equity-based compensation, based on the grant date fair value of the award. The Partnership measures liability awards under an equity-based payment arrangement based on remeasurementre-measurement of the award’s fair value at the conclusion of each interim and annual reporting period until the date of settlement, taking into consideration the probability that the performance conditions will be satisfied.

Restricted Unit Plans.In fiscal 2000 and fiscal 2009, the Partnership adopted the Suburban Propane Partners, L.P. 2000 Restricted Unit Plan and 2009 Restricted Unit Plan (collectively, the “Restricted Unit Plans”), respectively, which authorizes the issuance of Common Units to executives, managers and other employees and members of the Board of Supervisors of the Partnership. The total number of Common Units authorized for issuance under the Restricted Unit Plans was 1,906,9711,902,122 as of September 24, 2011. Unless27, 2014. In accordance with an August 6, 2013 amendment to the Restricted Unit Plans, unless otherwise stipulated by the Compensation Committee of the Partnership’s Board of Supervisors on or before the grant date, Restricted Unitsall restricted unit awards granted after the date of the amendment will vest 33.33% on each of the first three anniversaries of the award grant date. Prior to the August 6, 2013 amendment, unless otherwise stipulated by the Compensation Committee of the Partnership’s Board of Supervisors on or before the grant date, restricted units issued under the Restricted Unit Plans vest over time with 25% of the Common Units vesting at the end of each of the third and fourth anniversaries of the grant date and the remaining 50% of the Common Units vesting at the end of the fifth anniversary of the grant date. The Restricted Unit Plans participants are not eligible to receive quarterly distributions on, or vote, their respective restricted units until vested. Restricted units cannot be sold or transferred prior to vesting. The value of the restricted unit is established by the market price of the Common Unit on the date of grant, net of estimated future distributions during the vesting period. Restricted units are subject to forfeiture in certain circumstances as defined in the Restricted Unit Plans. Compensation expense for the unvested awards is recognized ratably over the vesting periods and is net of estimated forfeitures.

F-19


The following is a summary of activity in the Restricted Unit Plans:
         
      Weighted Average 
      Grant Date Fair 
  Units  Value Per Unit 
Outstanding September 27, 2008
  446,515  $30.57 
Granted  68,799   18.10 
Forfeited  (28,382)  (31.92)
Vested  (71,637)  (27.81)
        
Outstanding September 26, 2009
  415,295   28.89 
Granted  160,771   32.11 
Forfeited  (4,693)  (30.31)
Vested  (90,106)  (30.37)
        
Outstanding September 25, 2010
  481,267   29.67 
Granted  136,241   39.54 
Forfeited  (21,290)  (33.05)
Vested  (110,795)  (27.82)
        
Outstanding September 24, 2011
  485,423  $32.71 
        

   Units  Weighted
Average
Grant
Date Fair
Value
Per Unit
 

Outstanding September 24, 2011

   485,423   $32.71  

Granted

   108,674    32.60  

Forfeited

   (12,225  (30.78

Issued

   (139,021  (33.14
  

 

 

  

Outstanding September 29, 2012

   442,851    32.68  

Granted

   200,933    23.42  

Forfeited

   (3,497  (32.15

Issued

   (112,660  (32.01
  

 

 

  

Outstanding September 28, 2013

   527,627    29.30  

Granted

   256,273    37.43  

Forfeited

   (3,119  (28.39

Issued

   (85,854  (31.23
  

 

 

  

Outstanding September 27, 2014

   694,927   $32.07  
  

 

 

  

As of September 24, 2011,27, 2014, unrecognized compensation cost related to unvested restricted units awarded under the Restricted Unit Plans amounted to $6,320.$8,255. Compensation cost associated with the unvested awards is expected to be recognized over a weighted-average period of 1.81.4 years. Compensation expense for the Restricted Unit Plans for fiscal 2011, 20102014, 2013 and 20092012 was $3,922, $4,005$7,390, $3,888 and $2,396,$4,059, respectively.

Long-Term Incentive Plan.Plans.The Partnership has a non-qualified, unfunded long-term incentive plan for officers and key employees (the “LTIP”) which provides for payment, in the form of cash, forof an award of equity-based compensation at the end of a three-year performance period. TheFor the fiscal 2013 and 2012 awards, the level of compensation earned under the LTIP is based on the market performance of the Partnership’s Common Units on the basis of total return to Unitholders (“TRU”) compared to the TRU of a predetermined peer group comprisedconsisting solely of other publicly tradedmaster limited partnerships, (master limited partnerships), as approved by the Compensation Committee of the Board of Supervisors, over the same three-year performance period. On August 6, 2013, the Compensation Committee of the Partnership’s Board of Supervisors adopted the 2014 Long-Term Incentive Plan of the Partnership (“2014 LTIP”) as a replacement for the existing LTIP. As a result, for the fiscal 2014 award, the level of compensation earned under the 2014 LTIP is based on the average distribution coverage ratio over the same three-year performancemeasurement period. The average distribution coverage ratio is calculated as the Partnership’s average distributable cash flow, as defined in the 2014 LTIP, for each of the three years in the measurement period, subject to certain adjustments as set forth in the 2014 LTIP, divided by the amount of annualized cash distributions to be paid by the Partnership, based on the annualized cash distribution rate at the beginning of the measurement period. Compensation expense, which includes adjustments to previously recognized compensation expense for current period changes in the fair value of unvested awards, for fiscal 2011, 20102014, 2013 and 20092012 was $1,504, $3,058$120, $1,439 and $3,402,($340), respectively. The cash payouts in fiscal 2011, 20102014, 2013 and 2009,2012, which related to the fiscal 2008, 20072011, 2010 and 20062009 awards, were $2,697, $2,741$-0-, $-0- and $2,720,$3,336, respectively.

9.

10. Employee Benefit Plans

Defined Contribution Plan.The Partnership has an employee Retirement Savings and Investment Plan (the “401(k) Plan”) covering most employees. Employer matching contributions relating to the 401(k) Plan are a percentage of the participating employees’ elective contributions. The percentage of the Partnership’s contributions are based on a sliding scale depending on the Partnership’s achievement of annual performance targets. These contributions totaled $1,201, $2,504$1,848, $1,915 and $5,676$1,359 for fiscal 2011, 20102014, 2013 and 2009,2012, respectively.

Defined Pension and Retiree Health and Life Benefits Arrangements

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

F-20


Contributions, as needed, are made to a trust maintained by the Partnership. Contributions to the defined benefit pension plan are made by the Partnership in accordance with the Employee Retirement Income Security Act of 1974 minimum funding standards plus additional amounts made at the discretion of the Partnership, which may be determined from time to time. There were no minimum funding requirements for the defined benefit pension plan for fiscal 2011, 20102014, 2013 or 2009.2012. During the last decade, cash balance plans came under increased scrutiny which resulted in litigation pertaining to the cash balance feature and the Internal Revenue Service (“IRS”) issued additional regulations governing these types of plans. In fiscal 2010, the IRS completed its review of the Partnership’s defined benefit pension plan and issued a favorable determination letter pertaining to the cash balance formula. However, there can be no assurances that future legislative developments will not have an adverse effect on the Partnership’s results of operations or cash flows.

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

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

F-21


Projected Benefit Obligation, Fair Value of Plan Assets and Funded Status.The following tables provide a reconciliation of the changes in the benefit obligations and the fair value of the plan assets for fiscal 20112014 and 20102013 and a statement of the funded status for both years. Under the Partnership’s cash balance defined benefit pension plan, the accumulated benefit obligation and the projected benefit obligation are the same.
                 
          Retiree Health and Life 
  Pension Benefits  Benefits 
  2011  2010  2011  2010 
Reconciliation of benefit obligations:
                
Benefit obligation at beginning of year $157,626  $157,187  $20,932  $21,127 
Service cost        7   7 
Interest cost  6,822   7,503   855   1,013 
Actuarial loss  9,165   9,059   631   285 
Lump sum benefits paid  (6,365)  (7,889)      
Ordinary benefits paid  (8,129)  (8,234)  (1,530)  (1,500)
             
Benefit obligation at end of year $159,119  $157,626  $20,895  $20,932 
             
                 
Reconciliation of fair value of plan assets:
                
Fair value of plan assets at beginning of year $139,889  $140,055  $  $ 
Actual return on plan assets  7,503   15,957       
Employer contributions        1,530   1,500 
Lump-sum benefits paid  (6,365)  (7,889)      
Ordinary benefits paid  (8,129)  (8,234)  (1,530)  (1,500)
             
Fair value of plan assets at end of year $132,898  $139,889  $  $ 
             
                 
Funded status:
                
Funded status at end of year $(26,221) $(17,737) $(20,895) $(20,932)
             
                 
Amounts recognized in consolidated balance sheets consist of:
                
Net amount recognized at end of year $(26,221) $(17,737) $(20,895) $(20,932)
Less: Current portion        1,669   1,620 
             
Non-current benefit liability $(26,221) $(17,737) $(19,226) $(19,312)
             
                 
Amounts not yet recognized in net periodic benefit cost and included in accumulated other comprehensive income (loss):
                
Actuarial net (loss) gain $(59,502) $(56,267) $1,825  $2,492 
Prior service credits        2,358   2,848 
             
Net amount recognized in accumulated other comprehensive (loss) income $(59,502) $(56,267) $4,183  $5,340 
             

   Pension Benefits  Retiree Health and Life
Benefits
 
   2014  2013  2014  2013 

Reconciliation of benefit obligations:

     

Benefit obligation at beginning of year

  $148,631   $165,906   $17,754   $20,232  

Service cost

   —      —      5    8  

Interest cost

   5,774    5,229    640    586  

Actuarial loss (gain)

   8,459    (11,446  (278  (1,784

Lump sum benefits paid

   (5,401  (3,155  —      —    

Ordinary benefits paid

   (7,627  (7,903  (1,167  (1,288
  

 

 

  

 

 

  

 

 

  

 

 

 

Benefit obligation at end of year

  $149,836   $148,631   $16,954   $17,754  
  

 

 

  

 

 

  

 

 

  

 

 

 

Reconciliation of fair value of plan assets:

     

Fair value of plan assets at beginning of year

  $120,776   $133,873   $—     $—    

Actual return on plan assets

   10,023    (2,039  —      —    

Employer contributions

   —      —      1,167    1,288  

Lump sum benefits paid

   (5,401  (3,155  —      —    

Ordinary benefits paid

   (7,627  (7,903  (1,167  (1,288
  

 

 

  

 

 

  

 

 

  

 

 

 

Fair value of plan assets at end of year

  $117,771   $120,776   $—     $—    
  

 

 

  

 

 

  

 

 

  

 

 

 

Funded status:

     

Funded status at end of year

  $(32,065 $(27,855 $(16,954 $(17,754
  

 

 

  

 

 

  

 

 

  

 

 

 

Amounts recognized in consolidated balance sheets consist of:

     

Net amount recognized at end of year

  $(32,065 $(27,855 $(16,954 $(17,754

Less: Current portion

   —      —      1,276    1,427  
  

 

 

  

 

 

  

 

 

  

 

 

 

Non-current benefit liability

  $(32,065 $(27,855 $(15,678 $(16,327
  

 

 

  

 

 

  

 

 

  

 

 

 

Amounts not yet recognized in net periodic benefit cost and included in accumulated other comprehensive income (loss):

     

Actuarial net (loss) gain

  $(49,034 $(49,986 $3,780   $3,683  

Prior service credits

   —      —      889    1,379  
  

 

 

  

 

 

  

 

 

  

 

 

 

Net amount recognized in accumulated other comprehensive

     

(loss) income

  $(49,034 $(49,986 $4,669   $5,062  
  

 

 

  

 

 

  

 

 

  

 

 

 

Amounts recognized in other comprehensive income consisted ofincluded net actuarial losses (gains) arising during the period of $7,957$3,538 and $1,181($4,126) for pension benefits for fiscal 20112014 and 2010, respectively. Amounts recognized in other comprehensive income consisted of2013, respectively, and net actuarial losses(gains) arising during the period of $631($278) and $285($1,784) for other postretirement benefits for fiscal 20112014 and 2010,2013, respectively. The losses (gains)amounts in accumulated other comprehensive loss as of September 24, 201127, 2014 that are expected to be recognized as components of net periodic benefit costs during fiscal 20122015 are $5,271expenses of $4,522 and $(465)credits of $(686) for pension and other postretirement benefits, respectively.

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

F-22


The following table presents the actual allocation of assets held in trust as of September 24, 2011 and September 25, 2010:
         
  2011  2010 
         
Fixed income securities  88%  86%
Equity securities  12%  14%
       
   100%  100%
       
of:

   September 27,
2014
  September 28,
2013
 

Fixed income securities

   85  85

Equity securities

   15  15
  

 

 

  

 

 

 
   100  100
  

 

 

  

 

 

 

The fair valuesPartnership’s valuations include the use of the Partnership’s pension plan assetsfunds’ reported net asset values for commingled fund investments. Commingled funds are measuredvalued at the net asset value for their underlying securities. The Partnership further corroborates the valuations with observable market data using Levellevel 2 inputs.inputs within the fair value framework. The assets of the defined benefit pension plan have no significant concentration of risk and there are no restrictions on these investments.

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

         
  As of September 24,  As of September 25, 
  2011  2010 
Short term investments (1) $1,439  $1,259 
         
Equity securities: (1) (2)        
Domestic  10,823   13,042 
International  5,342   6,563 
         
Fixed income securities (1) (3)  115,294   119,025 
       
  $132,898  $139,889 
       
category as of:

   September 27,
2014
   September 28,
2013
 

Short term investments (1)

  $1,500    $1,516  

Equity securities: (1) (2)

    

Domestic

   6,370     11,780  

International

   10,916     5,959  

Fixed income securities (1) (3)

   98,985     101,521  
  

 

 

   

 

 

 
  $117,771    $120,776  
  

 

 

   

 

 

 

(1)Includes funds which are not publicly traded and are valued at the net asset value of the units provided by the fund issuer.
(2)Includes funds which invest primarily in a diversified portfolio of publicly traded USU.S. and Non-USNon-U.S. common stock.
(3)Includes funds which invest primarily in publicly traded and non-publicly traded, investment grade corporate bonds, U.S. government bonds and asset-backed securities.

Projected Contributions and Benefit Payments.There are no projected minimum funding requirements under the Partnership’s defined benefit pension plan for fiscal 2012.2015. Estimated future benefit payments for both pension and retiree health and life benefits are as follows:

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

Fiscal Year

  Pension
Benefits
   Retiree
Health
and
Life
Benefits
 

2015

  $32,316    $1,276  

2016

   12,632     1,202  

2017

   11,194     1,122  

2018

   11,317     1,048  

2019

   10,244     972  

2020 through 2024

   45,032     3,599  

Estimated future pension benefit payments assumes that age 65 or older active and non-active eligible participants in the pension plan that had not received a benefit payment prior to fiscal 20122015 will elect to receive a benefit payment in fiscal 2012.2015. In addition, for all periods presented, estimated future pension benefit payments assumes that participants will elect a lump sum payment in the fiscal year that the participant becomes eligible to receive benefits.

F-23


Effect on Operations.The following table provides the components of net periodic benefit costs included in operating expenses for fiscal 2011, 20102014, 2013 and 2009:
                         
  Pension Benefits  Retiree Health and Life Benefits 
  2011  2010  2009  2011  2010  2009 
 
Service cost $  $  $  $7  $7  $4 
Interest cost  6,822   7,503   9,487   855   1,013   1,381 
Expected return on plan assets  (6,295)  (8,080)  (9,205)         
Amortization of prior service credit           (490)  (490)  (490)
Settlement charge     2,818             
Recognized net actuarial loss  4,721   5,374   4,050   (35)  (65)  (312)
                   
Net periodic benefit costs $5,248  $7,615  $4,332  $337  $465  $583 
                   
During fiscal 2010, lump sum pension settlement payments to either terminated or retired individuals amounted to $7,889, which exceeded the settlement threshold (combined service and interest costs of net periodic pension cost) of $7,503 for fiscal 2010, and as a result, the Partnership was required to recognize a non-cash settlement charge of $2,818 during fiscal 2010. The non-cash charge was required to accelerate recognition of a portion of cumulative unamortized losses in the defined benefit pension plan. During fiscal 2011 and 2009, the amount of the pension benefit obligation settled through lump sum payments did not exceed the settlement threshold; therefore, a settlement charge was not required to be recognized in either of those fiscal years.
2012:

   Pension Benefits  Retiree Health and Life
Benefits
 
   2014  2013  2012  2014  2013  2012 

Service cost

  $—     $—     $—     $5   $8   $7  

Interest cost

   5,774    5,229    6,311    640    586    802  

Expected return on plan assets

   (5,102  (5,281  (5,665  —      —      —    

Amortization of prior service credit

   —      —      —      (490  (490  (490

Recognized net actuarial loss

   4,492    5,285    5,271    (181  —      —    
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Net periodic benefit costs

  $5,164   $5,233   $5,917   $(26 $104   $319  
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Actuarial Assumptions.The assumptions used in the measurement of the Partnership’s benefit obligations as of September 24, 201127, 2014 and September 25, 201028, 2013 are shown in the following table:

                 
          Retiree Health and 
  Pension Benefits  Life Benefits 
  2011  2010  2011  2010 
                 
Weighted-average discount rate  4.375%  4.750%  4.000%  4.250%
Average rate of compensation increase  n/a   n/a   n/a   n/a 

   Pension Benefits  Retiree Health
and Life Benefits
 
   2014  2013  2014  2013 

Weighted-average discount rate

   3.875  4.375  3.500  3.750

Average rate of compensation increase

   n/a    n/a    n/a    n/a  

Health care cost trend

   n/a    n/a    7.120  7.330

The assumptions used in the measurement of net periodic pension benefit and postretirement benefit costs for fiscal 2011, 20102014, 2013 and 20092012 are shown in the following table:

                         
  Pension Benefits  Retiree Health and Life Benefits 
  2011  2010  2009  2011  2010  2009 
                         
Weighted-average discount rate  4.750%  5.125%  7.625%  4.250%  5.000%  7.625%
Average rate of compensation increase  n/a   n/a   n/a   n/a   n/a   n/a 
Weighted-average expected long-term rate of return on plan assets  5.000%  6.250%  7.390%  n/a   n/a   n/a 
Health care cost trend  n/a   n/a   n/a   7.950%  8.150%  9.000%

   Pension Benefits  Retiree Health and Life
Benefits
 
   2014  2013  2012  2014  2013  2012 

Weighted-average discount rate

   4.375  3.500  4.375  3.750  3.000  4.000

Average rate of compensation increase

   n/a    n/a    n/a    n/a    n/a    n/a  

Weighted-average expected long- term rate of return on plan assets

   4.900  4.500  4.800  n/a    n/a    n/a  

Health care cost trend

   n/a    n/a    n/a    7.330  7.530  7.740

The discount rate assumption takes into consideration current market expectations related to long-term interest rates and the projected duration of the Partnership’s pension obligations based on a benchmark index with similar characteristics as the expected cash flow requirements of the Partnership’s defined benefit pension plan over the long-term. The expected long-term rate of return on plan assets assumption reflects estimated future performance in the Partnership’s pension asset portfolio considering the investment mix of the pension asset portfolio and historical asset performance. The expected return on plan assets is determined based on the expected long-term rate of return on plan assets and the market-related value of plan assets. The market-related value of pension plan assets is the fair value of the assets. Unrecognized actuarial gains and losses in excess of 10% of the greater of the projected benefit obligation and the market-related value of plan assets are amortized over the expected average remaining service period of active employees expected to receive benefits under the plan.

F-24


The 7.74%7.12% increase in health care costs assumed at September 24, 201127, 2014 is assumed to decrease gradually to 4.48% in fiscal 2028 and to remain at that level thereafter. An increase or decrease of the assumed health care cost trend rates by 1.0% in each year would have no material impact to the Partnership’s benefit obligation as of September 24, 201127, 2014 nor the aggregate of service and interest components of net periodic postretirement benefit expense for fiscal 2011.2014. The Partnership has concluded that the prescription drug benefits within the retiree medical plan do not entitle the Partnership to an available Medicare subsidy.

10.Multiemployer Pension Plans. As a result of the Inergy Propane Acquisition, the Partnership contributes to multiemployer pension plans (“MEPPs”) in accordance with various collective bargaining agreements covering union employees. As one of the many participating employers in these MEPPs, the Partnership is responsible with the other participating employers for any plan underfunding. During fiscal 2013, the Partnership established an accrual of $7,000 for its estimated obligation to certain MEPPs due to the Partnership’s voluntary partial withdrawal from one such MEPP and full withdrawal from four MEPPs. As of September 27, 2014, the accrual was $6,880 for its estimated obligation to these MEPPs. Due to the uncertainty regarding future factors that could trigger withdrawal liability, including the integration of Inergy Propane, the Partnership is unable to determine the amount and timing of any future withdrawal liability, if any.

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

While no multiemployer pension plan that the Partnership contributed to is individually significant to the Partnership, the table below discloses the three largest MEPPs to which the Partnership contributes. The financial health of a MEPP is indicated by the zone status, as defined by the PPA, which represents the funded status of the plan as certified by the plan’s actuary. Plans in the red zone are less than 65% funded, the yellow zone are between 65% and 80% funded, and green zone are at least 80% funded. Total contributions made by the Partnership to multiemployer pension plans for the fiscal year ended September 27, 2014 are shown below and reflect contributions made from the Inergy Propane Acquisition Date.

   

EIN/Pension
Plan Number

  

PPA Zone Status

  

FIP/RP
Status

  Contributions   Contributions greater
than 5% of Total
Plan Contributions
  

Expiration
date of
CBA

Pension Fund

    

2014

  

2013

    2014   2013   2012     

New England Teamsters & Trucking Industry Pension Fund

  04-6372430  Red (a)  Red (a)  Implemented  $616    $562    $30    No  April 2016 - March 2017

Local 282 Pension Trust Fund

  11-6245313  Green (b)  Green (b)  n/a   336     284     66    No  July 2019

Teamsters Industrial Employees Pension Fund

  22-6099363  Red (c)  Red (c)  Implemented   185     179     15    No  June 2017

Other (d)

           31     137     48    No  n/a
          

 

 

   

 

 

   

 

 

     
          $1,168    $1,162    $159      
          

 

 

   

 

 

   

 

 

     

(a)Based on most recent available valuation information for plan years ended September 2013.
(b)Based on most recent available valuation information for plan years ended February 2014.
(c)Based on most recent available valuation information for plan years ended December 2013.
(d)Includes the MEPPs from which the Partnership withdrew in fiscal 2013.

Additionally, the Partnership contributes to certain multi-employer plans that provide health and welfare benefits and defined annuity plans. Contributions to those plans were $1,897, $2,040 and $309 for fiscal 2014, fiscal 2013 and fiscal 2012, respectively.

11. Financial Instruments and Risk Management

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

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

The following summarizes the fair value of the Partnership’s derivative instruments and their location in the consolidated balance sheetsheets as of September 24, 201127, 2014 and September 25, 2010,28, 2013, respectively:

             
  As of September 24, 2011  As of September 25, 2010 
Asset Derivatives Location Fair Value  Location Fair Value 
Derivatives not designated as hedging instruments:            
Commodity options Other current assets $3,710  Other current assets $2,601 
  Other assets  612  Other assets   
             
Commodity futures Other current assets  1,132  Other current assets  22 
           
    $5,454    $2,623 
           
             
Liability Derivatives Location Fair Value  Location Fair Value 
Derivatives designated as hedging instruments:            
Interest rate swaps Other current liabilities $2,662  Other current liabilities $2,740 
  Other liabilities  1,934  Other liabilities  3,561 
           
   $4,596    $6,301 
           
Derivatives not designated as hedging instruments:            
Commodity options Other current liabilities $2,407  Other current liabilities $641 
  Other liabilities  69  Other liabilities   
             
Commodity futures Other current liabilities    Other current liabilities  1,838 
           
    $2,476    $2,479 
           

 

   As of September 27, 2014   As of September 28, 2013 
Asset Derivatives  Location   Fair Value   Location  Fair Value 

Derivatives not designated as hedging instruments:

        

Commodity-related derivatives

   Other current assets    $3,924    Other current assets  $2,546  
   Other assets     62    Other assets   716  
    

 

 

     

 

 

 
    $3,986      $3,262  
    

 

 

     

 

 

 
Liability Derivatives  Location   Fair Value   Location  Fair Value 

Derivatives designated as hedging instruments:

        

Interest rate swaps

   Other current liabilities    $1,257    Other current liabilities  $1,307  
   Other liabilities     283    Other liabilities   1,121  
    

 

 

     

 

 

 
  $1,540      $2,428  
    

 

 

     

 

 

 

Derivatives not designated as hedging instruments:

  

      

Commodity-related derivatives

   Other current liabilities    $1,527    Other current liabilities  $430  
   Other liabilities     53    Other liabilities   —    
    

 

 

     

 

 

 
    $1,580      $430  
    

 

 

     

 

 

 

F-25


The following summarizes the reconciliation of the beginning and ending balances of assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs:
                 
  Fair Value Measurement Using Significant 
  Unobservable Inputs (Level 3) 
  Fiscal 2011  Fiscal 2010 
  Assets  Liabilities  Assets  Liabilities 
Beginning balance of over-the-counter options $1,509  $30  $1,675  $844 
Beginning balance realized during the period  (1,509)  (30)  (1,434)  (844)
Change in the fair value of beginning balance        (241)   
Contracts purchased during the period  1,780   118   1,509   30 
             
Ending balance of over-the-counter options $1,780  $118  $1,509  $30 
             

   Fair Value Measurement Using Significant
Unobservable Inputs (Level 3)
 
   Fiscal 2014   Fiscal 2013 
   Assets  Liabilities   Assets  Liabilities 

Beginning balance of over-the-counter options

  $1,847   $—      $5,002   $1,209  

Beginning balance realized during the period

   (1,166  —       (4,400  (1,182

Contracts purchased during the period

   1,145    —       1,825    —    

Change in the fair value of outstanding contracts

   (314  —       (580  (27
  

 

 

  

 

 

   

 

 

  

 

 

 

Ending balance of over-the-counter options

  $1,512   $—      $1,847   $—    
  

 

 

  

 

 

   

 

 

  

 

 

 

As of September 24, 2011,27, 2014 and September 28, 2013, the Partnership’s outstanding commodity-related derivatives were scheduled to mature during the following 15 months, and have a weighted average maturity of approximately 4 months. As of September 25, 2010, the Partnership’s outstanding commodity-related derivatives were scheduled to mature during fiscal 2011, and had a weighted average maturity of approximately 3 months.

four and five months, respectively.

The effect of the Partnership’s derivative instruments on the consolidated statementstatements of operations for fiscal 2011, 20102014, 2013 and 20092012 are as follows:

             
  Amount of Gains  Gains (Losses) Reclassified from 
  (Losses) Recognized in  Accumulated OCI into Income 
  OCI  (Effective Portion) 
Derivatives in Cash Flow Hedging Relationships: (Effective Portion)  Location Amount 
             
Fiscal 2011            
Interest rate swap $(1,177) Interest expense $(2,881)
           
             
Fiscal 2010            
Interest rate swap $(5,706) Interest expense $(3,597)
           
             
Fiscal 2009            
Interest rate swap $(4,079) Interest expense $(3,088)
           
       
    Amount of 
    Unrealized 
  Location of Gains Gains (Losses) 
  (Losses) Recognized in Recognized in 
Derivatives Not Designated as Hedging Instruments: Income Income 
 
Fiscal 2011      
Options Cost of products sold $(1,517)
Futures Cost of products sold  2,948 
      
    $1,431 
      
Fiscal 2010      
Options Cost of products sold $(1,275)
Futures Cost of products sold  (4,125)
      
    $(5,400)
      
Fiscal 2009      
Options Cost of products sold $(589)
Futures Cost of products sold  2,302 
      
    $1,713 
      

 

   Amount of
(Losses) Gains
Recognized in OCI
(Effective Portion)
  Gains (Losses) Reclassified from
Accumulated OCI into Income
(Effective Portion)
 

Derivatives in Cash Flow Hedging Relationships:

   Location   Amount 

Interest rate swaps:

     

Fiscal 2014

  $(518  Interest expense    $(1,406
  

 

 

    

 

 

 

Fiscal 2013

  $584    Interest expense    $(2,465
  

 

 

    

 

 

 

Fiscal 2012

  $(3,561  Interest expense    $(2,680
  

 

 

    

 

 

 

F-26

Derivatives Not Designated as Hedging Instruments:

  Location of Gains
(Losses) Recognized in
Income
   Amount of
Unrealized
Gains
(Losses)
Recognized
in Income
 

Commodity-related derivatives:

    

Fiscal 2014

   Cost of products sold    $306  
    

 

 

 

Fiscal 2013

   Cost of products sold    $(4,318
    

 

 

 

Fiscal 2012

   Cost of products sold    $4,649  
    

 

 

 

The following table presents the fair value of the Partnership’s recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets subject to enforceable master netting arrangements or similar agreements:


   As of September 27, 2014 
   Gross
amounts
   Effects
of
netting
  Net
amounts
presented
in the
balance
sheet
 

Asset Derivatives

     

Commodity-related derivatives

  $9,533    $(5,547 $3,986  

Interest rate swap

   2,139     (2,139  —    
  

 

 

   

 

 

  

 

 

 
  $11,672    $(7,686 $3,986  
  

 

 

   

 

 

  

 

 

 

Liability Derivatives

     

Commodity-related derivatives

  $7,127    $(5,547 $1,580  

Interest rate swap

   3,679     (2,139  1,540  
  

 

 

   

 

 

  

 

 

 
  $10,806    $(7,686 $3,120  
  

 

 

   

 

 

  

 

 

 

   As of September 28, 2013 
   Gross
amounts
   Effects
of
netting
  Net
amounts
presented
in the
balance
sheet
 

Asset Derivatives

     

Commodity-related derivatives

  $3,634    $(372 $3,262  

Interest rate swap

   2,804     (2,804  —    
  

 

 

   

 

 

  

 

 

 
  $6,438    $(3,176 $3,262  
  

 

 

   

 

 

  

 

 

 

Liability Derivatives

     

Commodity-related derivatives

  $802    $(372 $430  

Interest rate swap

   5,232     (2,804  2,428  
  

 

 

   

 

 

  

 

 

 
  $6,034    $(3,176 $2,858  
  

 

 

   

 

 

  

 

 

 

The Partnership had no posted cash collateral as of September 27, 2014 and September 28, 2013 with its brokers for outstanding commodity-related derivatives.

Credit RiskConcentrations.. The Partnership’s principal customers are residential and commercial end users of propane and fuel oil and refined fuels served by approximately 300710 locations in 3041 states. No single customer accounted for more than 10% of revenues during fiscal 2011, 20102014, 2013 or 20092012 and no concentration of receivables exists as of September 24, 201127, 2014 or September 25, 2010. 28, 2013.

During fiscal 2011, 20102014, Crestwood Midstream Partners L.P., Targa Liquids Marketing and 2009, three suppliersTrade and Enterprise Products Partners L.P. provided approximately 37%19%, 38%13% and 40%, respectively,13% of our total propane purchases, respectively. No other single supplier accounted for more than 10% of the Partnership’s total propane supply.purchases in fiscal 2014. The Partnership believes that, if supplies from any of these three suppliers were interrupted, it would be able to secure adequate propane supplies from other sources without a material disruption of its operations.

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

Bank Debt and Senior Notes.The fair value of the Revolving Credit Facility approximates the carrying value since the interest rates are adjusted quarterly to reflect market conditions. Based upon quoted market prices, the fair value of the Partnership’s 2020 Senior Notes, 2021 Senior Notes and 2024 Senior Notes was $248,500$263,250, $363,489 and $508,594, respectively, as of September 24, 2011.

11.27, 2014.

12. Commitments and Contingencies

Commitments.The Partnership leases certain property, plant and equipment, including portions of the Partnership’s vehicle fleet, for various periods under noncancelable leases. Rental expense under operating leases was $18,868, $17,561$31,849, $33,036 and $17,254$23,593 for fiscal 2011, 20102014, 2013 and 2009,2012, respectively.

Future minimum rental commitments under noncancelable operating lease agreements as of September 24, 201127, 2014 are as follows:

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

Fiscal Year

  Minimum
Lease
Payments
 

2015

  $25,266  

2016

   17,781  

2017

   12,199  

2018

   9,224  

2019

   6,131  

2020 and thereafter

   7,469  

Contingencies.

Contingencies.

Self Insurance.As described in Note 2, the Partnership is self-insured for general and product, workers’ compensation and automobile liabilities up to predetermined amounts above which third party insurance applies. At September 24, 201127, 2014 and September 25, 2010,28, 2013, the Partnership had accrued liabilities of $52,841$62,450 and $55,445,$58,152, respectively, representing the total estimated losses under these self-insurance programs. For the portion of the estimated liability that exceeds insurance deductibles, the Partnership records an asset within other assets (or prepaid expenses and other current assets, as applicable) related to the amount of the liability expected to be covered by insurance which amounted to $17,513$18,410 and $17,990$18,330 as of September 24, 201127, 2014 and September 25, 2010,28, 2013, respectively.

Legal Matters.As described in Note 2, theThe Partnership’s operations are subject to all operating hazards and risks normally incidental to handling, storing and delivering combustible liquids such as propane. The Partnership has been, and will continue to be, a defendant in various legal proceedings and litigation arising in the ordinary course of business, both as a result of these operating hazards and risks, and as a result of other aspects of its business. In this regard,Although any litigation is inherently uncertain, based on past experience, the information currently available to the Partnership, currently is a defendant in putative suits in several states. The complaints allege a numberand the amount of claims, including as to the Partnership’s pricing, fee disclosure and tank ownership, under various consumer statutes, the Uniform Commercial Code, common law and antitrust law. Based on the nature of the allegations under these suits,its accrued insurance liabilities, the Partnership believesdoes not believe that the suits are without merit and are the Partnership is contesting eachcurrently pending or threatened litigation matters, or known claims or known contingent claims, will have a material adverse effect on its results of these suits vigorously. With respect to the pending putative suits, other than for legal defense fees and expenses based on the merits of the allegations, a liability for a loss contingency is not required.

operations, financial condition or cash flow.

F-27

13. Guarantees


12. Guarantees
The Partnership has residual value guarantees associated with certain of its operating leases, related primarily to transportation equipment, with remaining lease periods scheduled to expire periodically through fiscal 2018.2021. Upon completion of the lease period, the Partnership guarantees that the fair value of the equipment will equal or exceed the guaranteed amount, or the Partnership will pay the lessor the difference. Although the fair value of equipment at the end of its lease term has historically exceeded the guaranteed amounts, the maximum potential amount of aggregate future payments the Partnership could be required to make under these leasing arrangements, assuming the equipment is deemed worthless at the end of the lease term, is approximately $9,686.was $14,122 as of September 27, 2014. The fair value of residual value guarantees for outstanding operating leases was de minimis as of September 24, 201127, 2014 and September 25, 2010.
13.28, 2013.

14. Amounts Reclassified Out of Accumulated Other Comprehensive Income

The following table summarizes amounts reclassified out of accumulated other comprehensive (loss) income for the years ended September 27, 2014, September 28, 2013 and September 29, 2012:

   For the year ended September 27, 2014 
   Gains
and
Losses
on Cash
Flow
Hedges
  Pension
Benefits
  Postretirement
Benefits
  Total 

Balance, beginning of period

  $(2,428 $(49,987 $5,062   $(47,353
  

 

 

  

 

 

  

 

 

  

 

 

 

Other comprehensive income before reclassifications

   (518  —      —      (518

Amounts reclassified from accumulated other comprehensive income

   1,406(a)   953(b)   (393)(b)   1,966  
  

 

 

  

 

 

  

 

 

  

 

 

 

Net current period other comprehensive income

   888    953    (393  1,448  
  

 

 

  

 

 

  

 

 

  

 

 

 

Balance, end of period

  $(1,540 $(49,034 $4,669   $(45,905
  

 

 

  

 

 

  

 

 

  

 

 

 

   For the year ended September 28, 2013 
   Gains
and
Losses
on Cash
Flow
Hedges
  Pension
Benefits
  Postretirement
Benefits
  Total 

Balance, beginning of period

  $(5,477 $(59,398 $3,768   $(61,107
  

 

 

  

 

 

  

 

 

  

 

 

 

Other comprehensive income before reclassifications

   584    —      —      584  

Amounts reclassified from accumulated other comprehensive income

   2,465(a)   9,411(b)   1,294(b)   13,170  
  

 

 

  

 

 

  

 

 

  

 

 

 

Net current period other comprehensive income

   3,049    9,411    1,294    13,754  
  

 

 

  

 

 

  

 

 

  

 

 

 

Balance, end of period

  $(2,428 $(49,987 $5,062   $(47,353
  

 

 

  

 

 

  

 

 

  

 

 

 

   For the year ended September 29, 2012 
   Gains
and
Losses
on Cash
Flow
Hedges
  Pension
Benefits
  Postretirement
Benefits
  Total 

Balance, beginning of period

  $(4,596 $(59,503 $4,183   $(59,916
  

 

 

  

 

 

  

 

 

  

 

 

 

Other comprehensive income before reclassifications

   (3,561  —      —      (3,561

Amounts reclassified from accumulated other comprehensive income

   2,680(a)   105(b)   (415)(b)   2,370  
  

 

 

  

 

 

  

 

 

  

 

 

 

Net current period other comprehensive income

   (881  105    (415  (1,191
  

 

 

  

 

 

  

 

 

  

 

 

 

Balance, end of period

  $(5,477 $(59,398 $3,768   $(61,107
  

 

 

  

 

 

  

 

 

  

 

 

 

(a)Reclassification of realized losses on cash flow hedges are recognized in interest expense.
(b)These amounts are included in the computation of net periodic benefit cost. See Note 10, “Employee Benefit Plans”.

15. Public Offerings

On August 10, 2009,May 17, 2013, the Partnership sold 2,200,0002,700,000 Common Units in a public offering at a price of $41.50$48.16 per Common Unit, realizing proceeds of $86,700,$124,684, net of underwriting commissions and other offering expenses. On August 24, 2009,May 22, 2013, following the underwriters’ partial exercise of their over-allotment option, the Partnership sold an additional 230,934405,000 Common Units at $41.50$48.16 per Common Unit, generating additional proceeds of $18,760, net of underwriting commissions. The net proceeds of $9,180. The aggregatefrom the offering, including the net proceeds from the underwriters’ exercise of $95,880, along with cash on hand,their over-allotment option, were used to fundredeem $133,400 of the purchase of $175,000 aggregate principal amount of 2003Partnership’s 2021 Senior Notes pursuant to a cash tender offer.

14.in August 2013.

16. Segment Information

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

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

F-28


The fuel oil and refined fuels segment is primarily engaged in the retail distribution of fuel oil, diesel, kerosene and gasoline to residential and commercial customers for use primarily as a source of heat in homes and buildings.

The natural gas and electricity segment is engaged in the marketing of natural gas and electricity to residential and commercial customers in the deregulated energy markets of New York and Pennsylvania. Under this operating segment, the Partnership owns the relationship with the end consumer and has agreements with the local distribution companies to deliver the natural gas or electricity from the Partnership’s suppliers to the customer.

Activities in the “all other” category include the Partnership’s service business, which is primarily engaged in the sale, installation and servicing of a wide variety of home comfort equipment, particularly in the areas of heating and ventilation, and activities from the Partnership’s HomeTown Hearth & Grill and Suburban Franchising subsidiaries.

F-29


The following table presents certain data by reportable segment and provides a reconciliation of total operating segment information to the corresponding consolidated amounts for the periods presented:
             
  Year Ended 
  September 24,  September 25,  September 26, 
  2011  2010  2009 
Revenues:
            
Propane $929,492  $885,459  $864,012 
Fuel oil and refined fuels  139,572   135,059   159,596 
Natural gas and electricity  84,721   77,587   76,832 
All other  36,767   38,589   42,714 
          
Total revenues $1,190,552  $1,136,694  $1,143,154 
          
             
Operating income:
            
Propane $203,567  $230,717  $268,969 
Fuel oil and refined fuels  11,140   11,589   17,950 
Natural gas and electricity  11,667   11,629   12,791 
All other  (13,750)  (17,995)  (16,346)
Corporate  (69,396)  (82,572)  (72,749)
          
Total operating income  143,228   153,368   210,615 
             
Reconciliation to net income:            
Loss on debt extinguishment     9,473   4,624 
Interest expense, net  27,378   27,397   38,267 
Provision for income taxes  884   1,182   2,486 
          
Net income $114,966  $115,316  $165,238 
          
             
Depreciation and amortization:
            
Propane $19,525  $17,505  $15,951 
Fuel oil and refined fuels  4,139   3,277   4,253 
Natural gas and electricity  897   970   1,008 
All other  111   261   436 
Corporate  10,956   8,821   8,695 
          
Total depreciation and amortization $35,628  $30,834  $30,343 
          
         
  As of 
  September 24,  September 25, 
  2011  2010 
Assets:
        
Propane $706,008  $693,699 
Fuel oil and refined fuels  44,973   57,681 
Natural gas and electricity  18,675   21,552 
All other  3,719   3,042 
Corporate  183,084   194,940 
       
Total assets $956,459  $970,914 
       

 

   Year Ended 
   September 27,
2014
  September 28,
2013
  September 29,
2012
 

Revenues:

    

Propane

  $1,606,840   $1,357,102   $843,648  

Fuel oil and refined fuels

   194,684    208,957    114,288  

Natural gas and electricity

   87,093    79,432    67,419  

All other

   49,640    58,115    38,103  
  

 

 

  

 

 

  

 

 

 

Total revenues

  $1,938,257   $1,703,606   $1,063,458  
  

 

 

  

 

 

  

 

 

 

Operating income:

    

Propane

  $295,916   $287,473   $142,548  

Fuel oil and refined fuels

   2,473    (2,799  890  

Natural gas and electricity

   10,818    11,565    6,991  

All other

   (25,644  (26,483  (17,239

Corporate

   (93,437  (92,780  (91,533
  

 

 

  

 

 

  

 

 

 

Total operating income

   190,126    176,976    41,657  

Reconciliation to net income:

    

Loss on debt extinguishment

   11,589    2,144    2,249  

Interest expense, net

   83,261    95,427    38,633  

Provision for income taxes

   767    607    137  
  

 

 

  

 

 

  

 

 

 

Net income

  $94,509   $78,798   $638  
  

 

 

  

 

 

  

 

 

 

Depreciation and amortization:

    

Propane

  $106,491   $104,533   $34,826  

Fuel oil and refined fuels

   5,429    4,634    3,652  

Natural gas and electricity

   46    198    464  

All other

   699    638    345  

Corporate

   23,734    20,381    7,747  
  

 

 

  

 

 

  

 

 

 

Total depreciation and amortization

  $136,399   $130,384   $47,034  
  

 

 

  

 

 

  

 

 

 

F-30

   As of 
   September 27,
2014
   September 28,
2013
 

Assets:

    

Propane

  $2,365,320    $2,452,909  

Fuel oil and refined fuels

   69,360     77,473  

Natural gas and electricity

   13,992     16,789  

All other

   3,342     3,860  

Corporate

   157,349     176,956  
  

 

 

   

 

 

 

Total assets

  $2,609,363    $2,727,987  
  

 

 

   

 

 

 


INDEX TO FINANCIAL STATEMENT SCHEDULE

SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES

S-1


SCHEDULE II

SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES

VALUATION AND QUALIFYING ACCOUNTS

(in thousands)

                     
  Balance at  Charged          Balance 
  Beginning  (credited) to Costs  Other      at End 
  of Period  and Expenses  Additions  Deductions (a)  of Period 
                     
Year Ended September 26, 2009
                    
                     
Allowance for doubtful accounts $6,578  $3,284  $  $(5,488) $4,374 
Valuation allowance for deferred tax assets  48,895   (2,048)     (1,385)  45,462 
                     
Year Ended September 25, 2010
                    
                     
Allowance for doubtful accounts $4,374  $5,141  $  $(4,112) $5,403 
Valuation allowance for deferred tax assets  45,462   (4,806)        40,656 
                     
Year Ended September 24, 2011
                    
                     
Allowance for doubtful accounts $5,403  $5,598  $  $(4,041) $6,960 
Valuation allowance for deferred tax assets  40,656   (454)        40,202 

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

of Period
 

Year Ended September 29, 2012

        

Allowance for doubtful accounts

  $6,960    $838   $—      $(3,451 $4,347  

Valuation allowance for deferred tax assets

   40,202     (3,567  —       —      36,635  

Year Ended September 28, 2013

        

Allowance for doubtful accounts

  $4,347    $6,717   $—      $(4,278 $6,786  

Valuation allowance for deferred tax assets

   36,635     9,771    —       —      46,406  

Year Ended September 27, 2014

        

Allowance for doubtful accounts

  $6,786    $11,933   $—      $(7,597 $11,122  

Valuation allowance for deferred tax assets

   46,406     5,458    —       —     $51,864  

(a)Represents amounts that did not impact earnings.

 

S-2