Suburban Propane®
2 0 0 9 A N N U A L R E P O R T
PARTNERSHIP PROFILE
Suburban Propane Partners, L.P. (NYSE: SPH) has been in the customer service business since
1928. A Master Limited Partnership since 1996, Suburban is a value and growth-oriented
company managed for long-term, consistent performance.
Headquartered in Whippany, New Jersey, Suburban is a nationwide marketer and distributor of a
diverse array of products to meet the energy needs of our customers, specializing in propane, fuel
oil and refined fuels, as well as the marketing of natural gas and electricity in deregulated markets.
With more than 2,900 employees, Suburban maintains business operations in 30 states, providing
prompt, reliable service to approximately 850,000 residential, commercial, industrial and
agricultural customers through more than 300 locations.
During fiscal 2009, Suburban had retail propane sales of 343.9 million gallons which, based on
industry statistics, constitutes about 4% of the total domestic retail market. In addition, Suburban
had sales of fuel oil and other refined fuels of 57.4 million gallons in fiscal 2009. According to
Department of Energy statistics, of the 111.1 million households in the United States, 12.6 million
depend on propane for various uses and 8.4 million use fuel oil as their main heating fuel.
Propane is a derivative of natural gas processing and petroleum refining. It is clean burning,
abundant and available through an infrastructure of rail, barge, pipeline and truck transportation.
Propane is stored in caverns, terminals and bulk storage plants before it is delivered to end users.
Approximately 90% of the propane used in the United States is produced domestically. Fuel oil
comes from domestic wells and refineries in addition to imports from foreign countries.
Approximately 85% of the fuel oil consumed in the United States is refined domestically as part of
the “distillate fuel oil” product family, which includes fuel oil and diesel fuel. Fuel oil is
transported via barge, pipeline and truck transportation through terminals and bulk storage
plants before being delivered to end users.
SUBURBAN EXECUTIVE
MANAGEMENT
UNITHOLDER
INFORMATION
Executive Management
Michael J. Dunn, Jr.
President and Chief Executive Officer
Michael A. Stivala
Chief Financial Officer
Michael M. Keating
Senior Vice President — Administration
A. Davin D'Ambrosio
Vice President and Treasurer
Paul Abel
Vice President, General Counsel and Secretary
Mark Anton II
Vice President — Business Development
Steven C. Boyd
Vice President — Field Operations
Douglas T. Brinkworth
Vice President — Product Supply
Neil E. Scanlon
Vice President — Information Services
Mark Wienberg
Vice President — Operational Support and Analysis
Exchange Listing
Suburban Propane Partners, L.P. common units are
listed on the New York Stock Exchange under the ticker
symbol SPH.
Transfer Agent/Unitholder Records
Computershare Investor Services
By Mail:
Computershare Investor Services
P.O. Box 43078
Providence, RI 02940-3078
United States of America
By Overnight Delivery:
Computershare Investor Services
250 Royall Street
Canton, MA 02021
United States of America
Michael A. Kuglin
Controller and Chief Accounting Officer
Telephone: +1 781-575-2724
Web Address: www.computershare.com
Board of Supervisors
Harold R. Logan, Jr.*
Chairman
John D. Collins*
Dudley C. Mecum*
John Hoyt Stookey*
Jane Swift*
Michael J. Dunn, Jr.
* Member of both the Audit Committee and the Compensation Committee
Investor Information
Copies of Annual Reports, Interim Reports and other
publications are available without charge from:
Suburban Propane Partners, L.P.
Investor Relations
P.O. Box 206
Whippany, New Jersey 07981-0206
Telephone: 973-503-9252
Web Address: www.suburbanpropane.com
Refer to our website for:
• Company news, including the scheduling of analyst calls
• Earnings releases
• K-1’s
It is anticipated that K-1’s will be available on our website
and mailed to each Unitholder in late February 2010.
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] Annual Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
For the fiscal year ended September 26, 2009
[ ] Transition Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
Commission File Number: 1-14222
SUBURBAN PROPANE PARTNERS, L.P.
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of
incorporation or organization)
22-3410353
(I.R.S. Employer
Identification No.)
240 Route 10 West
Whippany, NJ 07981
(973) 887-5300
(Address, including zip code, and telephone number,
including area code, of registrant’s principal executive offices)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Common Units
Name of each exchange on which registered
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes [X] No [ ]
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes [ ] No [X]
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive
Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12
months (or for such shorter period that the registrant was required to submit and post such files). *
Yes No * The registrant has not yet been phased into the interactive data requirements.
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this
Form 10-K or any amendment to this Form 10-K. [X]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting
company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the
Exchange Act. (Check one):
Large accelerated filer
Non-accelerated filer (do not check if a smaller reporting company)
Accelerated filer
Smaller reporting company
Indicate by check mark whether registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes [ ]
No [X]
The aggregate market value as of March 27, 2009 of the registrant’s Common Units held by non-affiliates of the registrant, based on the
reported closing price of such units on the New York Stock Exchange on such date ($36.96 per unit), was approximately $1,212,166,000.
Documents Incorporated by Reference: None
Total number of pages (excluding Exhibits): 143
SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES
INDEX TO ANNUAL REPORT ON FORM 10-K
PART I
Page
ITEM 1.
ITEM 1A.
ITEM 1B.
ITEM 2.
ITEM 3.
ITEM 4.
BUSINESS......................................................................................................................
1
RISK FACTORS............................................................................................................. 11
UNRESOLVED STAFF COMMENTS........................................................................... 21
PROPERTIES.................................................................................................................. 21
LEGAL PROCEEDINGS................................................................................................ 21
SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.................... 22
PART II
ITEM 5.
ITEM 6.
ITEM 7.
ITEM 7A.
ITEM 8.
ITEM 9.
ITEM 9A.
ITEM 9B.
MARKET FOR THE REGISTRANT’S COMMON UNITS, RELATED
UNITHOLDER MATTERS AND ISSUER PURCHASES OF UNITS......................... 23
SELECTED FINANCIAL DATA................................................................................... 24
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS.......................................................
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK..................................................................................…..................….. 48
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA...........................…. 51
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE….......................................…...… 54
CONTROLS AND PROCEDURES................................................................................ 54
OTHER INFORMATION............................................................................................... 55
28
PART III
ITEM 10.
ITEM 11.
ITEM 12.
ITEM 13.
ITEM 14.
DIRECTORS, EXECUTIVE OFFICERS AND PARTNERSHIP GOVERNANCE...... 56
EXECUTIVE COMPENSATION............................................................…................... 61
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT AND RELATED UNITHOLDER MATTERS........................ 97
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND
DIRECTOR INDEPENDENCE.. .................................................................................... 99
PRINCIPAL ACCOUNTING FEES AND SERVICES.............................................…. 100
ITEM 15.
EXHIBITS, FINANCIAL STATEMENT SCHEDULES............................................... 101
SIGNATURES............................................................…........................................................................... 102
PART IV
DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K contains forward-looking statements (“Forward-Looking Statements”) as
defined in the Private Securities Litigation Reform Act of 1995 and Section 27A of the Securities Act of 1933, as
amended, relating to future business expectations and predictions and financial condition and results of
operations of Suburban Propane Partners, L.P. (the “Partnership”). Some of these statements can be identified by
the use of forward-looking terminology such as “prospects,” “outlook,” “believes,” “estimates,” “intends,”
“may,” “will,” “should,” “anticipates,” “expects” or “plans” or the negative or other variation of these or similar
words, or by discussion of trends and conditions, strategies or risks and uncertainties. These Forward-Looking
Statements involve certain risks and uncertainties that could cause actual results to differ materially from those
discussed or implied in such Forward-Looking Statements (statements contained in this Annual Report
identifying such risks and uncertainties are referred to as “Cautionary Statements”). The risks and uncertainties
and their impact on the Partnership’s results include, but are not limited to, the following risks:
• The impact of weather conditions on the demand for propane, fuel oil and other refined fuels, natural gas and
electricity;
• Volatility in the unit cost of propane, fuel oil and other refined fuels and natural gas, the impact of the
Partnership’s hedging and risk management activities, and the adverse impact of price increases on volumes
as a result of customer conservation;
• The ability of the Partnership to compete with other suppliers of propane, fuel oil and other energy sources;
• The impact on the price and supply of propane, fuel oil and other refined fuels from the political, military or
economic instability of the oil producing nations, global terrorism and other general economic conditions;
• The ability of the Partnership to acquire and maintain reliable transportation for its propane, fuel oil and
other refined fuels;
• The ability of the Partnership to retain customers;
• The impact of customer conservation, energy efficiency and technology advances on the demand for propane
and fuel oil;
• The ability of management to continue to control expenses;
• The impact of changes in applicable statutes and government regulations, or their interpretations, including
those relating to the environment and global warming and other regulatory developments on the Partnership’s
business;
• The impact of changes in tax regulations that could adversely affect the tax treatment of the Partnership for
federal income tax purposes;
• The impact of legal proceedings on the Partnership’s business;
• The impact of operating hazards that could adversely affect the Partnership’s operating results to the extent
not covered by insurance;
• The Partnership’s ability to make strategic acquisitions and successfully integrate them;
• The impact of current conditions in the global capital and credit markets, and general economic pressures;
and
• Other risks referenced from time to time in filings with the Securities and Exchange Commission (“SEC”)
and those factors listed or incorporated by reference into this Annual Report under “Risk Factors”.
Some of these Forward-Looking Statements are discussed in more detail in “Management’s Discussion and Analysis of
Financial Condition and Results of Operations” in this Annual Report. On different occasions, the Partnership or its
representatives have made or may make Forward-Looking Statements in other filings with the SEC, press releases or oral
statements made by or with the approval of one of the Partnership’s authorized executive officers. Readers are cautioned not
to place undue reliance on Forward-Looking Statements, which reflect management’s view only as of the date made. The
Partnership undertakes no obligation to update any Forward-Looking Statement or Cautionary Statement, except as required
by law. All subsequent written and oral Forward-Looking Statements attributable to the Partnership or persons acting on its
behalf are expressly qualified in their entirety by the Cautionary Statements in this Annual Report and in future SEC reports.
For a more complete discussion of specific factors which could cause actual results to differ from those in the Forward-
Looking Statements or Cautionary Statements, see “Risk Factors” in this Annual Report.
PART I
ITEM 1. BUSINESS
Development of Business
Suburban Propane Partners, L.P. (the “Partnership”), a publicly traded Delaware limited partnership, is a
nationwide marketer and distributor of a diverse array of products meeting the energy needs of our customers. We
specialize in the distribution of propane, fuel oil and refined fuels, as well as the marketing of natural gas and
electricity in deregulated markets. In support of our core marketing and distribution operations, we install and
service a variety of home comfort equipment, particularly in the areas of heating and ventilation. We believe,
based on LP/Gas Magazine dated February 2009, that we are the fourth largest retail marketer of propane in the
United States, measured by retail gallons sold in the year 2008. As of September 26, 2009, we were serving the
energy needs of approximately 850,000 active residential, commercial, industrial and agricultural customers through
approximately 300 locations in 30 states located primarily in the east and west coast regions of the United States,
including Alaska. We sold approximately 343.9 million gallons of propane and 57.4 million gallons of fuel oil and
refined fuels to retail customers during the year ended September 26, 2009. Together with our predecessor
companies, we have been continuously engaged in the retail propane business since 1928.
We conduct our business principally through Suburban Propane, L.P., a Delaware limited partnership, which
operates our propane business and assets (the “Operating Partnership”), and its direct and indirect subsidiaries.
Our general partner, and the general partner of our Operating Partnership, is Suburban Energy Services Group
LLC (the “General Partner”), a Delaware limited liability company. Since October 19, 2006, the General Partner
has had no economic interest in either the Partnership or the Operating Partnership other than as a holder of 784
Common Units of the Partnership. Prior to October 19, 2006, the General Partner was majority-owned by senior
management of the Partnership and owned an approximate combined 1.75% general partner interest in the
Partnership and the Operating Partnership.
On October 19, 2006, the Partnership, the Operating Partnership and the General Partner consummated an
Exchange Agreement by and among the parties dated July 27, 2006 (the “Exchange Agreement”), pursuant to
which the Partnership issued 2,300,000 Common Units to the General Partner in exchange for the cancellation of
the General Partner’s incentive distribution rights (“IDRs”), the economic interest in the Partnership included in
the general partner interest therein and the economic interest in the Operating Partnership included in the general
partner interest therein (the “GP Exchange Transaction”). Pursuant to a Distribution, Release and Lockup
Agreement dated July 27, 2006 by and among the Partnership, the Operating Partnership, the General Partner and
the then individual members of the General Partner (the “Distribution Agreement”), the Common Units received
by the General Partner (other than 784 Common Units that will remain in the General Partner) were distributed to
the then members of the General Partner in exchange for their interests in the General Partner.
In addition to the GP Exchange Transaction, the Partnership adopted the Third Amended and Restated
Agreement of Limited Partnership (the “Partnership Agreement”), which amended the previous partnership
agreement to, among other things, effectuate the GP Exchange Transaction. Under the Partnership Agreement,
the General Partner will continue to be the general partner of both the Partnership and the Operating Partnership,
but its general partner interests will have no economic value (which means that such general partner interests do
not entitle the holder thereof to any cash distributions of either partnership, or to any cash payment upon the
liquidation of either partnership, or any other economic rights in either partnership). Following the GP Exchange
Transaction and the consummation of the Distribution Agreement, the sole member of the General Partner is the
Chief Executive Officer of the Partnership and the General Partner holds 784 Common Units received in the GP
Exchange Transaction. The Partnership continues to own all of the limited partner interests in the Operating
Partnership, with 0.1% thereof held through a limited liability company, wholly-owned (directly and indirectly)
by the Partnership. Additionally, under the Partnership Agreement no IDRs are outstanding and no provisions
1
for future IDRs are contained in the Partnership Agreement. The Common Units represent 100% of the limited
partner interests in the Partnership.
Subsidiaries of the Operating Partnership include Suburban Sales and Service, Inc. (the “Service Company”),
which conducts a portion of the Partnership’s service work and appliance and parts businesses. The Service
Company is the sole member of Gas Connection, LLC (d/b/a HomeTown Hearth & Grill), and Suburban
Franchising, LLC. HomeTown Hearth & Grill sells and installs natural gas and propane gas grills, fireplaces and
related accessories and supplies through four retail stores in the northwest and northeast regions as of September
26, 2009. Suburban Franchising creates and develops propane related franchising business opportunities.
Through an acquisition in fiscal 2004, we transformed our business from a marketer of a single fuel into one
that provides multiple energy solutions, with expansion into the marketing and distribution of fuel oil and refined
fuels, as well as the marketing of natural gas and electricity. Our fuel oil and refined fuels, natural gas and
electricity and services businesses are structured as corporate entities (collectively referred to as “Corporate
Entities”) and, as such, are subject to corporate level income tax.
Suburban Energy Finance Corporation, a direct wholly-owned subsidiary of the Partnership, was formed on
November 26, 2003 to serve as co-issuer, jointly and severally with the Partnership, of the Partnership’s
unsecured 6.875% senior notes due December 2013. Suburban Energy Finance Corporation has nominal assets
and conducts no business operations.
In this Annual Report, unless otherwise indicated, the terms “Partnership,” “we,” “us,” and “our” are used to
refer to Suburban Propane Partners, L.P. and its consolidated subsidiaries, including the Operating Partnership.
The Partnership, the Operating Partnership and the Service Company commenced operations in March 1996 in
connection with the Partnership’s initial public offering of Common Units.
We currently file Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and current reports on
Form 8-K with the SEC. You may read and receive copies of any materials that we file with the SEC at the
SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information on
the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Any information filed by us
is also available on the SEC’s EDGAR database at www.sec.gov.
Upon written request or through a link from our website at www.suburbanpropane.com, we will provide,
without charge, copies of our Annual Report on Form 10-K for the year ended September 26, 2009, each of the
Quarterly Reports on Form 10-Q, current reports filed or furnished on Form 8-K and all amendments to such
reports as soon as is reasonably practicable after such reports are electronically filed with or furnished to the
SEC. Requests should be directed to: Suburban Propane Partners, L.P., Investor Relations, P.O. Box 206,
Whippany, New Jersey 07981-0206.
Our Strategy
Our business strategy is to deliver increasing value to our Unitholders through initiatives, both internal and
external, that are geared toward achieving sustainable profitable growth and increased quarterly distributions. The
following are key elements of our strategy:
Internal Focus on Driving Operating Efficiencies, Right-Sizing Our Cost Structure and Enhancing Our
Customer Mix. We focus internally on improving the efficiency of our existing operations, managing our cost
structure and improving our customer mix. Through investments in our technology infrastructure, we continue to
seek to improve operating efficiencies and the return on assets employed. Beginning at the end of fiscal 2005 and
continuing throughout much of fiscal 2007, we implemented specific plans to streamline our operating footprint and
management structure, eliminate redundant functions and assets through enhanced operating efficiencies, and
refocus our service activities on offerings to support our existing customer base within our core operating segments.
2
While the majority of the specific initiatives under these plans were executed by the end of fiscal 2007, our focus on
operating efficiencies and on our cost structure is an ongoing process. Our internal efforts are particularly focused
in the areas of route optimization, forecasting customer usage, inventory control, cash management and customer
tracking.
In addition, we continually evaluate our customer base and, in particular, focus on customers that provide a
proper return. In that regard, our efforts to strategically exit certain lower margin business in both our propane
and fuel oil and refined fuels segments has resulted in a reduction in volumes sold, yet has had a favorable
impact on overall segment profitability.
Growing Our Customer Base by Improving Customer Retention and Acquiring New Customers. We set
clear objectives to focus our employees on seeking new customers and retaining existing customers by providing
world-class customer service. We believe that customer satisfaction is a critical factor in the growth and success of
our operations. “Our Business is Customer Satisfaction” is one of our core operating philosophies. We measure
and reward our customer service centers based on a combination of profitability of the individual customer service
center and net customer growth.
Selective Acquisitions of Complementary Businesses or Assets. Externally, we seek to extend our presence or
diversify our product offerings through selective acquisitions. Our acquisition strategy is to focus on businesses
with a relatively steady cash flow that will extend our presence in strategically attractive markets, complement our
existing business segments or provide an opportunity to diversify our operations with other energy-related assets.
While we are active in this area, we are also very patient and deliberate in evaluating acquisition candidates. There
were no acquisitions completed during fiscal 2009, 2008 or 2007 as we focused internally on driving efficiencies
and reducing costs. However, during fiscal 2007 we completed a non-cash transaction in which we disposed of
nine customer service centers considered to be in markets that were non-strategic to our operations in exchange
for three customer service centers located in Alaska, thus expanding our presence in this strategically attractive
market.
Selective Disposition of Non-Strategic Assets. We continuously evaluate our existing facilities to identify
opportunities to optimize our return on assets by selectively divesting operations in slower growing markets,
generating proceeds that can be reinvested in markets that present greater opportunities for growth. Our objective is
to fully exploit the growth and profit potential of all of our assets. In that regard, in fiscal 2008 we completed the
sale of our Tirzah, South Carolina underground granite propane storage cavern, and associated 62-mile pipeline,
for approximately $53.7 million in net proceeds which have been reinvested in the business.
Business Segments
We manage and evaluate our operations in five operating segments, three of which are reportable segments:
Propane, Fuel Oil and Refined Fuels and Natural Gas and Electricity. These business segments are described
below. See the Notes to the Consolidated Financial Statements included in this Annual Report for financial
information about our business segments.
Propane is a by-product of natural gas processing and petroleum refining. It is a clean burning energy source
recognized for its transportability and ease of use relative to alternative forms of stand-alone energy sources.
Propane use falls into three broad categories:
Propane
•
•
•
residential and commercial applications;
industrial applications; and
agricultural uses.
3
In the residential and commercial markets, propane is used primarily for space heating, water heating, clothes
drying and cooking. Industrial customers use propane generally as a motor fuel to power over-the-road vehicles,
forklifts and stationary engines, to fire furnaces, as a cutting gas and in other process applications. In the
agricultural market, propane is primarily used for tobacco curing, crop drying, poultry brooding and weed control.
Propane is extracted from natural gas or oil wellhead gas at processing plants or separated from crude oil during
the refining process. It is normally transported and stored in a liquid state under moderate pressure or refrigeration
for ease of handling in shipping and distribution. When the pressure is released or the temperature is increased,
propane becomes a flammable gas that is colorless and odorless, although an odorant is added to allow its detection.
Propane is clean burning and, when consumed, produces only negligible amounts of pollutants.
Product Distribution and Marketing
We distribute propane through a nationwide retail distribution network consisting of approximately 300
locations in 30 states as of September 26, 2009. Our operations are concentrated in the east and west coast regions
of the United States, including Alaska. As of September 26, 2009, we serviced approximately 702,000 active
propane customers. Typically, our customer service centers are located in suburban and rural areas where natural
gas is not readily available. Generally, these customer service centers consist of an office, appliance showroom,
warehouse and service facilities, with one or more 18,000 to 30,000 gallon storage tanks on the premises. Most of
our residential customers receive their propane supply through an automatic delivery system that eliminates the
customer’s need to make an affirmative purchase decision. These deliveries are scheduled through computer
technology, based upon each customer’s historical consumption patterns and prevailing weather conditions.
Additionally, as is common practice in the industry, we offer our customers a budget payment plan whereby the
customer’s estimated annual propane purchases and service contracts are paid for in a series of estimated equal
monthly payments over a twelve-month period. From our customer service centers, we also sell, install and service
equipment to customers who purchase propane from us including heating and cooking appliances, hearth products
and supplies and, at some locations, propane fuel systems for motor vehicles.
We sell propane primarily to six customer markets: residential, commercial, industrial (including engine fuel),
agricultural, other retail users and wholesale. Approximately 96% of the propane gallons sold by us in fiscal 2009
were to retail customers: 44% to residential customers, 31% to commercial customers, 8% to industrial customers,
6% to agricultural customers and 11% to other retail users. The balance of approximately 4% of the propane
gallons sold by us in fiscal 2009 was for risk management activities and wholesale customers. Sales to residential
customers in fiscal 2009 accounted for approximately 61% of our margins on retail propane sales, reflecting the
higher-margin nature of the residential market. No single customer accounted for 10% or more of our propane
revenues during fiscal 2009.
Retail deliveries of propane are usually made to customers by means of bobtail and rack trucks. Propane is
pumped from bobtail trucks, which have capacities ranging from 2,125 gallons to 2,975 gallons of propane, into a
stationary storage tank on the customers’ premises. The capacity of these storage tanks ranges from approximately
100 gallons to approximately 1,200 gallons, with a typical tank having a capacity of 300 to 400 gallons. As is
common in the propane industry, we own a significant portion of the storage tanks located on our customers’
premises. We also deliver propane to retail customers in portable cylinders, which typically have a capacity of 5 to
35 gallons. When these cylinders are delivered to customers, empty cylinders are refilled in place or transported for
replenishment at our distribution locations. We also deliver propane to certain other bulk end users in larger trucks
known as transports, which have an average capacity of approximately 9,000 gallons. End users receiving transport
deliveries include industrial customers, large-scale heating accounts, such as local gas utilities that use propane as a
supplemental fuel to meet peak load delivery requirements, and large agricultural accounts that use propane for crop
drying.
In our wholesale operations, we principally sell propane to large industrial end users and other propane
distributors. The wholesale market includes customers who use propane to fire furnaces, as a cutting gas and in
4
other process applications. Due to the low margin nature of the wholesale market as compared to the retail market,
we have reduced our emphasis on wholesale marketing over the last several years.
Supply
Our propane supply is purchased from approximately 52 oil companies and natural gas processors at
approximately 125 supply points located in the United States and Canada. We make purchases primarily under one-
year agreements that are subject to annual renewal, and also purchase propane on the spot market. Supply contracts
generally provide for pricing in accordance with posted prices at the time of delivery or the current prices
established at major storage points, and some contracts include a pricing formula that typically is based on
prevailing market prices. Some of these agreements provide maximum and minimum seasonal purchase guidelines.
Propane is generally transported from refineries, pipeline terminals, storage facilities (including our storage facility
in Elk Grove, California) and coastal terminals to our customer service centers by a combination of common
carriers, owner-operators and railroad tank cars. See Item 2 of this Annual Report.
Historically, supplies of propane have been readily available from our supply sources. Although we make no
assurance regarding the availability of supplies of propane in the future, we currently expect to be able to secure
adequate supplies during fiscal 2010. During fiscal 2009, Targa Liquids Marketing and Trade (“Targa”) and LDH
Energy Mont Belvieu, L.P. (“LDH”) provided approximately 19% and 12% of our total propane purchases,
respectively. The availability of our propane supply is dependent on several factors, including the severity of winter
weather and the price and availability of competing fuels, such as natural gas and fuel oil. We believe that if
supplies from Targa or LDH were interrupted, we would be able to secure adequate propane supplies from other
sources without a material disruption of our operations. Nevertheless, the cost of acquiring such propane might be
higher and, at least on a short-term basis, margins could be affected. Approximately 95% of our total propane
purchases were from domestic suppliers in fiscal 2009.
We seek to reduce the effect of propane price volatility on our product costs and to help ensure the availability
of propane during periods of short supply. We are currently a party to forward and option contracts with various
third parties to purchase and sell propane at fixed prices in the future. These activities are monitored by our senior
management through enforcement of our Hedging and Risk Management Policy. See Items 7 and 7A of this Annual
Report.
We own and operate a large propane storage facility in California. We also operate smaller storage facilities in
other locations and have rights to use storage facilities in additional locations (including our former facility in
Tirzah, South Carolina). These storage facilities enable us to buy and store large quantities of propane particularly
during periods of low demand, which generally occur during the summer months. This practice helps ensure a more
secure supply of propane during periods of intense demand or price instability. As of September 26, 2009, the
majority of our storage capacity in California was leased to third parties.
Competition
According to the U.S. Census Bureau, in a 2008 American Community Survey on house heating fuel, propane
accounts for approximately 5% of household energy consumption in the United States. This level has not changed
materially over the previous two decades. As an energy source, propane competes primarily with natural gas,
electricity and fuel oil, principally on the basis of price, availability and portability.
Propane is more expensive than natural gas on an equivalent British Thermal Unit basis in locations serviced by
natural gas, but it is an alternative to natural gas in rural and suburban areas where natural gas is unavailable or
portability of product is required. Historically, the expansion of natural gas into traditional propane markets has
been inhibited by the capital costs required to expand pipeline and retail distribution systems. Although the recent
extension of natural gas pipelines to previously unserved geographic areas tends to displace propane distribution in
those areas, we believe new opportunities for propane sales have been arising as new neighborhoods are developed
5
in geographically remote areas.
We also have some relative advantages over suppliers of other energy sources. For example, propane is
generally less expensive to use than electricity for space heating, water heating, clothes drying and cooking. Fuel oil
has not been a significant competitor due to the current geographical diversity of our operations, and propane and
fuel oil are not significant competitors because of the cost of converting from one to the other.
In addition to competing with suppliers of other energy sources, our propane operations compete with other
retail propane distributors. The retail propane industry is highly fragmented and competition generally occurs on a
local basis with other large full-service multi-state propane marketers, thousands of smaller local independent
marketers and farm cooperatives. Based on industry statistics contained in 2007 Sales of Natural Gas Liquids and
Liquefied Refinery Gases, as published by the American Petroleum Institute in December 2008, and LP/Gas
Magazine dated February 2009, the ten largest retailers, including us, account for approximately 37% of the total
retail sales of propane in the United States. For fiscal years 2009 and 2007, no single marketer had a greater than
10% share of the total retail propane market in the United States. For fiscal year 2008 one marketer had more
than a 10% share of the total retail propane market in the United States. Most of our customer service centers
compete with five or more marketers or distributors. However, each of our customer service centers operates in its
own competitive environment because retail marketers tend to locate in close proximity to customers in order to
lower the cost of providing service. Our typical customer service center has an effective marketing radius of
approximately 50 miles, although in certain rural areas the marketing radius may be extended by a satellite office.
Product Distribution and Marketing
Fuel Oil and Refined Fuels
We market and distribute fuel oil, kerosene, diesel fuel and gasoline to approximately 67,000 residential and
commercial customers in the northeast region of the United States. Sales of fuel oil and refined fuels for fiscal
2009 amounted to 57.4 million gallons. Approximately 65% of the fuel oil and refined fuels gallons sold by us in
fiscal 2009 were to residential customers, principally for home heating, 4% were to commercial customers, 1%
were to agricultural and 4% to other users. Sales of diesel and gasoline accounted for the remaining 26% of total
volumes sold in this segment during fiscal 2009. Fuel oil has a more limited use, compared to propane, for space
and water heating in residential and commercial buildings. We sell diesel fuel and gasoline to commercial and
industrial customers for use primarily to propel motor vehicles. Due to the low margin nature of the diesel fuel
and gasoline businesses, at the end of fiscal 2005 we made a decision to reduce our emphasis on these activities
and, in certain instances, exited the business.
Approximately 54% of our fuel oil customers receive their fuel oil under an automatic delivery system
without the customer having to make an affirmative purchase decision. These deliveries are scheduled through
computer technology, based upon each customer’s historical consumption patterns and prevailing weather
conditions. Additionally, as is common practice in the industry, we offer our customers a budget payment plan
whereby the customer’s estimated annual fuel oil purchases and service contracts are paid for in a series of
estimated equal monthly payments over a twelve-month period. From our customer service centers, we also sell,
install and service equipment to customers who purchase fuel oil from us including heating appliances.
Deliveries of fuel oil are usually made to customers by means of tankwagon trucks, which have capacities
ranging from 2,500 gallons to 3,000 gallons. Fuel oil is pumped from the tankwagon truck into a stationary storage
tank that is located on the customer’s premises, which is owned by the customer. The capacity of customer storage
tanks ranges from approximately 275 gallons to approximately 1,000 gallons. No single customer accounted for
10% or more of our fuel oil revenues during fiscal 2009.
6
Supply
We obtain fuel oil and other refined fuels in either pipeline, truckload or tankwagon quantities, and have
contracts with certain pipeline and terminal operators for the right to temporarily store fuel oil at 13 terminal
facilities we do not own. We have arrangements with certain suppliers of fuel oil, which provide open access to
fuel oil at specific terminals throughout the northeast. Additionally, a portion of our purchases of fuel oil are
made at local wholesale terminal racks. In most cases, the supply contracts do not establish the price of fuel oil
in advance; rather, prices are typically established based upon market prices at the time of delivery plus or minus
a differential for transportation and volume discounts. We purchase fuel oil from more than 20 suppliers at
approximately 60 supply points. While fuel oil supply is more susceptible to longer periods of supply constraint
than propane, we believe that our supply arrangements will provide us with sufficient supply sources. Although
we make no assurance regarding the availability of supplies of fuel oil in the future, we currently expect to be able to
secure adequate supplies during fiscal 2010.
Competition
The fuel oil industry is a mature industry with total demand expected to remain relatively flat to moderately
declining. The fuel oil industry is highly fragmented, characterized by a large number of relatively small,
independently owned and operated local distributors. We compete with other fuel oil distributors offering a
broad range of services and prices, from full service distributors to those that solely offer the delivery service.
We have developed a wide range of sales programs and service offerings for our fuel oil customer base in an
attempt to be viewed as a full service energy provider and to build customer loyalty. For instance, like most
companies in the fuel oil business, we provide home heating equipment repair service to our fuel oil customers
through our services business on a 24-hour a day basis. The fuel oil business unit also competes for retail
customers with suppliers of alternative energy sources, principally natural gas, propane and electricity.
Natural Gas and Electricity
We market natural gas and electricity through our wholly-owned subsidiary Agway Energy Services, LLC
(“AES”) in the deregulated markets of New York and Pennsylvania primarily to residential and small
commercial customers. Historically, local utility companies provided their customers with all three aspects of
electric and natural gas service: generation, transmission and distribution. However, under deregulation, public
utility commissions in several states are licensing energy service companies, such as AES, to act as alternative
suppliers of the commodity to end consumers. In essence, we make arrangements for the supply of electricity or
natural gas to specific delivery points. The local utility companies continue to distribute electricity and natural
gas on their distribution systems. The business strategy of this business segment is to expand its market share by
concentrating on growth in the customer base and expansion into other deregulated markets that are considered
strategic markets.
We serve nearly 76,000 natural gas and electricity customers in New York and Pennsylvania. During fiscal
2009, we sold approximately 3.6 million dekatherms of natural gas and 489.4 million kilowatt hours of electricity
through the natural gas and electricity segment. Approximately 71% of our customers were residential
households and the remainder was small commercial and industrial customers. New accounts are obtained
through numerous marketing and advertising programs, including telemarketing and direct mail initiatives. Most
local utility companies have established billing service arrangements whereby customers receive a single bill
from the local utility company which includes distribution charges from the local utility company, as well as
product charges for the amount of natural gas or electricity provided by AES and utilized by the customer. We
have arrangements with several local utility companies that provide billing and collection services for a fee.
Under these arrangements, we are paid by the local utility company for all or a portion of customer billings after
a specified number of days following the customer billing with no further recourse to AES.
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Supply of natural gas is arranged through annual supply agreements with major national wholesale
suppliers. Pricing under the annual natural gas supply contracts is based on posted market prices at the time of
delivery, and some contracts include a pricing formula that typically is based on prevailing market prices. The
majority of our electricity requirements is purchased through the New York Independent System Operator
(“NYISO”) under an annual supply agreement, as well as purchase arrangements through other national
wholesale suppliers on the open market. Electricity pricing under the NYISO agreement is based on local market
indices at the time of delivery. Competition is primarily with local utility companies, as well as other marketers
of natural gas and electricity providing similar alternatives as AES.
All Other
We sell, install and service various types of whole-house heating products, air cleaners, humidifiers,
hearth products and space heaters to the customers of our propane, fuel oil, natural gas and electricity products.
Our supply needs are filled through supply arrangements with several large regional equipment manufacturers
and distribution companies. Competition in this business segment is primarily with small, local heating and
ventilation providers and contractors, as well as, to a lesser extent, other regional service providers. The focus of
our ongoing service offerings are in support of the service needs of our existing customer base within our
propane, refined fuels and natural gas and electricity business segments. Additionally, we have entered into
arrangements with third-party service providers to complement and, in certain instances, supplement our existing
service capabilities.
In addition, activities from our HomeTown Hearth & Grill and Suburban Franchising subsidiaries are also
included in the all other business category.
Seasonality
The retail propane and fuel oil distribution businesses, as well as the natural gas marketing business, are
seasonal because the primary use of these fuels is for heating residential and commercial buildings. Historically,
approximately two-thirds of our retail propane volume is sold during the six-month peak heating season from
October through March. The fuel oil business tends to experience greater seasonality given its more limited use
for space heating and approximately three-fourths of our fuel oil volumes are sold between October and March.
Consequently, sales and operating profits are concentrated in our first and second fiscal quarters. Cash flows
from operations, therefore, are greatest during the second and third fiscal quarters when customers pay for
product purchased during the winter heating season. We expect lower operating profits and either net losses or
lower net income during the period from April through September (our third and fourth fiscal quarters).
Weather conditions have a significant impact on the demand for our products, in particular propane, fuel oil
and natural gas, for both heating and agricultural purposes. Many of our customers rely heavily on propane, fuel
oil or natural gas as a heating source. Accordingly, the volume sold is directly affected by the severity of the
winter weather in our service areas, which can vary substantially from year to year. In any given area, sustained
warmer than normal temperatures will tend to result in reduced propane, fuel oil and natural gas consumption,
while sustained colder than normal temperatures will tend to result in greater consumption.
Trademarks and Tradenames
We utilize a variety of trademarks and tradenames owned by us, including “Suburban Propane,” “Gas
Connection,” “Suburban Cylinder Express” and “HomeTown Hearth & Grill.” Additionally, we hold rights to
certain trademarks and tradenames, including “Agway Propane,” “Agway” and “Agway Energy Products” in
connection with the distribution of petroleum-based fuel and sales and service of heating and ventilation. We
regard our trademarks, tradenames and other proprietary rights as valuable assets and believe that they have
significant value in the marketing of our products and services.
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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 pollutants and establish standards for the handling
of solid and hazardous wastes and can require the investigation and cleanup of environmental contamination.
These laws include the Resource Conservation and Recovery Act, the Comprehensive Environmental Response,
Compensation and Liability Act (“CERCLA”), the Clean Air Act, the Occupational Safety and Health Act, the
Emergency Planning and Community Right to Know Act, the Clean Water Act and comparable state statutes.
CERCLA, also known as the “Superfund” law, imposes joint and several liability without regard to fault or the
legality of the original conduct on certain classes of persons that are considered to have contributed to the release
or threatened release of a “hazardous substance” into the environment. Propane is not a hazardous substance
within the meaning of CERCLA, whereas some constituents contained in fuel oil are considered hazardous
substances. We own real property at locations where such hazardous substances may be present as a result of
prior activities.
We expect that we will be required to expend funds to participate in the remediation of certain sites,
including sites where we have been designated by the Environmental Protection Agency as a potentially
responsible party under CERCLA and at sites with aboveground and underground fuel storage tanks. We will
also incur other expenses associated with environmental compliance. We continually monitor our operations
with respect to potential environmental issues, including changes in legal requirements and remediation
technologies.
Through an acquisition in fiscal 2004, we acquired certain properties with either known or probable
environmental exposure, some of which are currently in varying stages of investigation, remediation or
monitoring. Additionally, we identified that certain active sites acquired contained environmental conditions
which required further investigation, future remediation or ongoing monitoring activities. The environmental
exposures included instances of soil and/or groundwater contamination associated with the handling and storage
of fuel oil, gasoline and diesel fuel. As of September 26, 2009, we had accrued environmental liabilities of $1.7
million representing the total estimated future liability for remediation and monitoring.
Estimating the extent of our responsibility at a particular site, and the method and ultimate cost of
remediation of that site, requires making numerous assumptions. As a result, the ultimate cost to remediate any
site may differ from current estimates, and will depend, in part, on whether there is additional contamination, not
currently known to us, at that site. However, we believe that our past experience provides a reasonable basis for
estimating these liabilities. As additional information becomes available, estimates are adjusted as necessary.
While we do not anticipate that any such adjustment would be material to our financial statements, the result of
ongoing or future environmental studies or other factors could alter this expectation and require recording
additional liabilities. We currently cannot determine whether we will incur additional liabilities or the extent or
amount of any such liabilities.
National Fire Protection Association (“NFPA”) Pamphlet Nos. 54 and 58, which establish rules and
procedures governing the safe handling of propane, or comparable regulations, have been adopted, in whole, in
part or with state addenda, as the industry standard for propane storage, distribution and equipment installation
and operation in all of the states in which we operate. In some states these laws are administered by state
agencies, and in others they are administered on a municipal level. Pamphlet No. 58 has adopted storage tank
valve retrofit requirements due to be completed by June 2011 or later depending on when each state adopts the
2001 edition of NFPA Pamphlet No. 58. We have a program in place to meet this deadline.
NFPA Pamphlet Nos. 30, 30A, 31, 385 and 395, which establish rules and procedures governing the safe
handling of distillates (fuel oil, kerosene and diesel fuel) and gasoline, or comparable regulations, have been
adopted, in whole, in part or with state addenda, as the industry standard for fuel oil, kerosene, diesel fuel and
gasoline storage, distribution and equipment installation/operation in all of the states in which we sell those
9
products. In some states these laws are administered by state agencies and in others they are administered on a
municipal level.
With respect to the transportation of propane, distillates and gasoline by truck, we are subject to regulations
promulgated under the Federal Motor Carrier Safety Act. These regulations cover the transportation of
hazardous materials and are administered by the United States Department of Transportation or similar state
agencies. We conduct ongoing training programs to help ensure that our operations are in compliance with
applicable safety regulations. We maintain various permits that are necessary to operate some of our facilities,
some of which may be material to our operations. We believe that the procedures currently in effect at all of our
facilities for the handling, storage and distribution of propane, distillates and gasoline are consistent with
industry standards and are in compliance, in all material respects, with applicable laws and regulations.
The Department of Homeland Security (“DHS”) has published regulations under 6 CFR Part 27 Chemical
Facility Anti-Terrorism Standards. Our facilities are registered with the DHS – we have 468 facilities
determined to be “Not a High Risk Chemical Facility” and 16 facilities determined to be Tier 4 (lowest level of
security risk). Security Vulnerability Assessments for each of the 16 facilities have been submitted to DHS for
review. Because our facilities are currently operating under the security programs developed under guidelines
issued by the Department of Transportation, Department of Labor and Environmental Protection Agency, we do
not anticipate that we will incur significant costs in order to comply with these DHS regulations.
On June 26, 2009, the U.S. House of Representatives approved adoption of the “American Clean Energy and
Security Act of 2009,” also known as the “Waxman-Markey cap-and-trade legislation” (“ACESA”). The purpose
of ACESA is to control and reduce emissions of “greenhouse gases” (“GHGs”) in the United States. GHGs are
certain gases, including carbon dioxide and methane, that may contribute to the warming of the Earth’s
atmosphere and other climatic changes. ACESA would establish an economy-wide cap on emissions of GHGs in
the United States and would require certain regulated entities to obtain GHG emission “allowances”
corresponding to the annual emission of GHGs attributable to their products or operations. Regulated entities
under ACESA include producers of natural gas liquids (“NGLs”), local natural gas distribution companies and
certain industrial facilities. Under ACESA, the number of authorized emission allowances would decline each
year, resulting in an expected and progressive increase in the cost or value of the allowances. The net effect of
maintaining emission allowances under ACESA would be to increase the costs associated with the combusting of
carbon-based fuels such as natural gas, NGLs (including propane), and refined petroleum products.
The U.S. Senate has begun work on its own legislation for controlling and reducing domestic GHG
emissions, and President Obama has indicated his support of legislation to reduce GHG emissions through an
emission allowance system. Although it is not possible at this time to predict if or when the Senate may act on
climate change legislation or how any Senate bill would be reconciled with ACESA, any adopted laws or
regulations that restrict or reduce GHG emissions could require us to incur increased operating costs and could
adversely affect demand for the products and services we provide.
Future developments, such as stricter environmental, health or safety laws and regulations thereunder, could
affect our operations. We do not anticipate that the cost of our compliance with environmental, health and safety
laws and regulations, including CERCLA, as currently in effect and applicable to known sites will have a
material adverse effect on our financial condition or results of operations. To the extent we discover any
environmental liabilities presently unknown to us or environmental, health or safety laws or regulations are made
more stringent, however, there can be no assurance that our financial condition or results of operations will not
be materially and adversely affected.
Congress is currently considering legislation to impose restrictions on certain transactions involving
derivatives, which could affect the use of derivatives in hedging transactions. ACESA contains provisions that
would prohibit private energy commodity derivative and hedging transactions. ACESA would expand the power
of the Commodity Futures Trading Commission (“CFTC”), to regulate derivative transactions related to energy
10
commodities, including oil and natural gas, and to mandate clearance of such derivative contracts through
registered derivative clearing organizations. Under ACESA, the CFTC’s expanded authority over energy
derivatives would terminate upon the adoption of general legislation covering derivative regulatory reform. The
Chairman of the CFTC has announced that the CFTC intends to conduct hearings to determine whether to set
limits on trading and positions in commodities with finite supply, particularly energy commodities, such as crude
oil, natural gas and other energy products. The CFTC also is evaluating whether position limits should be applied
consistently across all markets and participants. In addition, the Treasury Department recently has indicated that
it intends to propose legislation to subject all OTC derivative dealers and all other major OTC derivative market
participants to substantial supervision and regulation, including by imposing conservative capital and margin
requirements and strong business conduct standards. Derivative contracts that are not cleared through central
clearinghouses and exchanges may be subject to substantially higher capital and margin requirements. Although
it is not possible at this time to predict whether or when Congress may act on derivatives legislation or how any
climate change bill approved by the Senate would be reconciled with ACESA, any laws or regulations that may
be adopted that subject us to additional capital or margin requirements relating to, or to additional restrictions on,
our hedging and commodity positions could have an adverse effect on our ability to hedge risks associated with
our business or on the cost of our hedging activity.
Employees
As of September 26, 2009, we had 2,783 full time employees, of whom 493 were engaged in general and
administrative activities (including fleet maintenance), 38 were engaged in transportation and product supply
activities and 2,252 were customer service center employees. As of September 26, 2009, 61 of our employees were
represented by 6 different local chapters of labor unions. We believe that our relations with both our union and
non-union employees are satisfactory. From time to time, we hire temporary workers to meet peak seasonal
demands.
ITEM 1A. RISK FACTORS
You should carefully consider the specific risk factors set forth below as well as the other information
contained or incorporated by reference in this Annual Report. Some factors in this section are Forward-Looking
Statements. See “Disclosure Regarding Forward-Looking Statements” above.
Risks Inherent in our Business Operations
Since weather conditions may adversely affect demand for propane, fuel oil and other refined fuels and
natural gas, our results of operations and financial condition are vulnerable to warm winters.
Weather conditions have a significant impact on the demand for propane, fuel oil and other refined fuels
and natural gas for both heating and agricultural purposes. Many of our customers rely heavily on propane, fuel
oil or natural gas as a heating source. The volume of propane, fuel oil and natural gas sold is at its highest during
the six-month peak heating season of October through March and is directly affected by the severity of the
winter. Typically, we sell approximately two-thirds of our retail propane volume and approximately three-fourths
of our retail fuel oil volume during the peak heating season.
Actual weather conditions can vary substantially from year to year, significantly affecting our financial
performance. For example, average temperatures in our service territories were slightly warmer than normal for
the year ended September 26, 2009 compared to 6% warmer than normal temperatures in both fiscal 2008 and
fiscal 2007, as measured by the number of heating degree days reported by the National Oceanic and
Atmospheric Administration. Furthermore, variations in weather in one or more regions in which we operate can
significantly affect the total volume of propane, fuel oil and other refined fuels and natural gas we sell and,
consequently, our results of operations. Variations in the weather in the northeast, where we have a greater
11
concentration of higher margin residential accounts and substantially all of our fuel oil and natural gas
operations, generally have a greater impact on our operations than variations in the weather in other markets. We
can give no assurance that the weather conditions in any quarter or year will not have a material adverse effect on
our operations, or that our available cash will be sufficient to pay principal and interest on our indebtedness and
distributions to unitholders.
Sudden increases in the price of propane, fuel oil and other refined fuels and natural gas due to, among other
things, our inability to obtain adequate supplies from our usual suppliers, may adversely affect our operating
results.
Our profitability in the retail propane, fuel oil and refined fuels and natural gas businesses is largely
dependent on the difference between our product cost and retail sales price. Propane, fuel oil and other refined
fuels and natural gas are commodities, and the unit price we pay is subject to volatile changes in response to
changes in supply or other market conditions over which we have no control, including the severity of winter
weather and the price and availability of competing alternative energy sources. In general, product supply
contracts permit suppliers to charge posted prices at the time of delivery or the current prices established at major
supply points, including Mont Belvieu, Texas, and Conway, Kansas. In addition, our supply from our usual
sources may be interrupted due to reasons that are beyond our control. As a result, the cost of acquiring propane,
fuel oil and other refined fuels and natural gas from other suppliers might be materially higher at least on a short-
term basis. Since we may not be able to pass on to our customers immediately, or in full, all increases in our
wholesale cost of propane, fuel oil and other refined fuels and natural gas, these increases could reduce our
profitability. We engage in transactions to manage the price risk associated with certain of our product costs from
time to time in an attempt to reduce cost volatility and to help ensure availability of product during periods of
short supply. We can give no assurance that future volatility in propane, fuel oil and natural gas supply costs will
not have a material adverse effect on our profitability and cash flow, or that our available cash will be sufficient
to pay principal and interest on our indebtedness and distributions to our unitholders.
Because of the highly competitive nature of the retail propane and fuel oil businesses, we may not be able to
retain existing customers or acquire new customers, which could have an adverse impact on our operating
results and financial condition.
The retail propane and fuel oil industries are mature and highly competitive. We expect overall demand for
propane to remain relatively constant over the next several years, while we expect the overall demand for fuel oil
to be relatively flat to moderately declining during the same period. Year-to-year industry volumes of propane
and fuel oil are expected to be primarily affected by weather patterns and from competition intensifying during
warmer than normal winters, as well as from the impact of a sustained higher commodity price environment on
customer conservation.
Propane and fuel oil compete in the alternative energy sources market with electricity, natural gas and other
existing and future sources of energy, some of which are, or may in the future be, less costly for equivalent
energy value. For example, natural gas is a significantly less expensive source of energy than propane and fuel
oil. As a result, except for some industrial and commercial applications, propane and fuel oil are generally not
economically competitive with natural gas in areas where natural gas pipelines already exist. The gradual
expansion of the nation’s natural gas distribution systems has made natural gas available in many areas that
previously depended upon propane or fuel oil. Propane and fuel oil compete to a lesser extent with each other
due to the cost of converting from one to the other.
In addition to competing with other sources of energy, our propane and fuel oil businesses compete with
other distributors principally on the basis of price, service, availability and portability. Competition in the retail
propane business is highly fragmented and generally occurs on a local basis with other large full-service multi-
state propane marketers, thousands of smaller local independent marketers and farm cooperatives. Our fuel oil
business competes with fuel oil distributors offering a broad range of services and prices, from full service
12
distributors to those offering delivery only. In addition, our existing fuel oil customers, unlike our existing
propane customers, generally own their own tanks, which can result in intensified competition for these
customers.
As a result of the highly competitive nature of the retail propane and fuel oil businesses, our growth within
these industries depends on our ability to acquire other retail distributors, open new customer service centers, add
new customers and retain existing customers. We believe our ability to compete effectively depends on reliability
of service, responsiveness to customers and our ability to control expenses in order to maintain competitive
prices.
Energy efficiency, general economic conditions and technological advances have affected and may continue
to affect demand for propane and fuel oil by our retail customers.
The national trend toward increased conservation and technological advances, including installation of
improved insulation and the development of more efficient furnaces and other heating devices, has adversely
affected the demand for propane and fuel oil by our retail customers which, in turn, has resulted in lower sales
volumes to our customers. In addition, recent economic conditions may lead to additional conservation by retail
customers seeking to further reduce their heating costs, particularly during periods of sustained higher
commodity prices as has been the case over the past three fiscal years. Future technological advances in heating,
conservation and energy generation may adversely affect our financial condition and results of operations.
Current conditions in the global capital and credit markets, and general economic pressures may adversely
affect our financial position and results of operations.
Our business and operating results are materially affected by worldwide economic conditions. Current
conditions in the global capital and credit markets and general economic pressures have led to declining
consumer and business confidence, increased market volatility and widespread reduction of business activity
generally. As a result of this turmoil, coupled with increasing energy prices, our customers may experience cash
flow shortages which may lead to delayed or cancelled plans to purchase our products, and affect the ability of
our customers to pay for our products. In addition, disruptions in the U.S. residential mortgage market, increases
in mortgage foreclosure rates and failures of lending institutions may adversely affect retail customer demand for
our products (in particular, products used for home heating and home comfort equipment) and our business and
results of operations.
Our operating results and ability to generate sufficient cash flow to pay principal and interest on our
indebtedness, and to pay distributions to unitholders, may be affected by our ability to continue to control
expenses.
The propane and fuel oil industries are mature and highly fragmented with competition from other multi-
state marketers and thousands of smaller local independent marketers. Demand for propane and fuel oil is
expected to be affected by many factors beyond our control, including, but not limited to, the severity of weather
conditions during the peak heating season, customer conservation driven by high energy costs and other
economic factors, as well as technological advances impacting energy efficiency. Accordingly, our propane and
fuel oil sales volumes and related gross margins may be negatively affected by these factors beyond our control.
Our operating profits and ability to generate sufficient cash flow may depend on our ability to continue to control
expenses in line with sales volumes. We can give no assurance that we will be able to continue to control
expenses to the extent necessary to reduce the effect on our profitability and cash flow from these factors.
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The risk of terrorism and political unrest and the current hostilities in the Middle East or other energy
producing regions may adversely affect the economy and the price and availability of propane, fuel oil and
other refined fuels and natural gas.
Terrorist attacks and political unrest and the current hostilities in the Middle East or other energy producing
regions may adversely impact the price and availability of propane, fuel oil and other refined fuels and natural
gas, as well as our results of operations, our ability to raise capital and our future growth. The impact that the
foregoing may have on our industry in general, and on us in particular, is not known at this time. An act of terror
could result in disruptions of crude oil or natural gas supplies and markets (the sources of propane and fuel oil),
and our infrastructure facilities could be direct or indirect targets. Terrorist activity may also hinder our ability to
transport propane, fuel oil and other refined fuels if our means of supply transportation, such as rail or pipeline,
become damaged as a result of an attack. A lower level of economic activity could result in a decline in energy
consumption, which could adversely affect our revenues or restrict our future growth. Instability in the financial
markets as a result of terrorism could also affect our ability to raise capital. Terrorist activity and hostilities in the
Middle East or other energy producing regions could likely lead to increased volatility in prices for propane, fuel
oil and other refined fuels and natural gas. We have opted to purchase insurance coverage for terrorist acts within
our property and casualty insurance programs, but we can give no assurance that our insurance coverage will be
adequate to fully compensate us for any losses to our business or property resulting from terrorist acts.
Our financial condition and results of operations may be adversely affected by governmental regulation and
associated environmental and health and safety costs.
Our business is subject to a wide range of federal, state and local laws and regulations related to
environmental and health and safety matters including those concerning, among other things, the investigation
and remediation of contaminated soil and groundwater and transportation of hazardous materials. These
requirements are complex, changing and tend to become more stringent over time. In addition, we are required to
maintain various permits that are necessary to operate our facilities, some of which are material to our operations.
There can be no assurance that we have been, or will be, at all times in complete compliance with all legal,
regulatory and permitting requirements or that we will not incur significant costs in the future relating to such
requirements. Violations could result in penalties, or the curtailment or cessation of operations.
Moreover, currently unknown environmental issues, such as the discovery of additional contamination, may
result in significant additional expenditures, and potentially significant expenditures also could be required to
comply with future changes to environmental laws and regulations or the interpretation or enforcement thereof.
Such expenditures, if required, could have a material adverse effect on our business, financial condition or results
of operations.
We are subject to operating hazards and litigation risks that could adversely affect our operating results to the
extent not covered by insurance.
Our operations are subject to all operating hazards and risks normally associated with handling, storing and
delivering combustible liquids such as propane, fuel oil and other refined fuels. As a result, we have been, and
are likely to continue to be, a defendant in various legal proceedings and litigation arising in the ordinary course
of business. We are self-insured for general and product, workers’ compensation and automobile liabilities up to
predetermined amounts above which third-party insurance applies. We cannot guarantee that our insurance will
be adequate to protect us from all material expenses related to potential future claims for personal injury and
property damage or that these levels of insurance will be available at economical prices, or that all legal matters
that arise will be covered by our insurance programs.
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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 foresee only limited growth in total retail demand
for propane and flat to moderately declining retail demand for fuel oil. With respect to our retail propane
business, it may be difficult for us to increase our aggregate number of retail propane customers except through
acquisitions. As a result, we expect the success of our financial performance to depend, in part, upon our ability
to acquire other retail propane and fuel oil distributors or other energy-related businesses and to successfully
integrate them into our existing operations and to make cost saving changes. The competition for acquisitions is
intense and we can make no assurance that we will be able to acquire other propane and fuel oil distributors or
other energy-related businesses on economically acceptable terms or, if we do, to integrate the acquired
operations effectively.
The adoption of climate change legislation by Congress could result in increased operating costs and reduced
demand for the products and services we provide.
On June 26, 2009, the U.S. House of Representatives approved adoption of the “American Clean Energy
and Security Act of 2009,” also known as the “Waxman-Markey cap-and-trade legislation” (“ACESA”). The
purpose of ACESA is to control and reduce emissions of “greenhouse gases” (“GHGs”) in the United States.
GHGs are certain gases, including carbon dioxide and methane, that may contribute to the warming of the Earth’s
atmosphere and other climatic changes. ACESA would establish an economy-wide cap on emissions of GHGs in
the United States and would require certain regulated entities to obtain GHG emission “allowances”
corresponding to the annual emission of GHGs attributable to their products or operations. Regulated entities
under ACESA include producers of natural gas liquids (“NGLs”), local natural gas distribution companies, and
certain industrial facilities. Under ACESA, the number of authorized emission allowances would decline each
year, resulting in an expected and progressive increase in the cost or value of the allowances. The net effect of
maintaining emission allowances under ACESA would be to increase the costs associated with the combusting of
carbon-based fuels such as natural gas, NGLs (including propane), and refined petroleum products.
The U.S. Senate has begun work on its own legislation for controlling and reducing domestic GHG
emissions, and President Obama has indicated his support of legislation to reduce GHG emissions through an
emission allowance system. Although it is not possible at this time to predict if or when the Senate may act on
climate change legislation or how any Senate bill would be reconciled with ACESA, any adopted laws or
regulations that restrict or reduce GHG emissions could require us to incur increased operating costs and could
adversely affect demand for the products and services we provide.
The adoption of derivatives legislation by Congress could have an adverse impact on our ability to hedge risks
associated with our business.
Congress is currently considering legislation to impose restrictions on certain transactions involving
derivatives, which could affect the use of derivatives in hedging transactions. ACESA contains provisions that
would prohibit private energy commodity derivative and hedging transactions. ACESA would expand the power
of the Commodity Futures Trading Commission, (“CFTC”), to regulate derivative transactions related to energy
commodities, including oil and natural gas, and to mandate clearance of such derivative contracts through
registered derivative clearing organizations. Under ACESA, the CFTC’s expanded authority over energy
derivatives would terminate upon the adoption of general legislation covering derivative regulatory reform. The
Chairman of the CFTC has announced that the CFTC intends to conduct hearings to determine whether to set
limits on trading and positions in commodities with finite supply, particularly energy commodities, such as crude
oil, natural gas and other energy products. The CFTC also is evaluating whether position limits should be applied
consistently across all markets and participants. In addition, the Treasury Department recently has indicated that
it intends to propose legislation to subject all OTC derivative dealers and all other major OTC derivative market
participants to substantial supervision and regulation, including by imposing conservative capital and margin
15
requirements and strong business conduct standards. Derivative contracts that are not cleared through central
clearinghouses and exchanges may be subject to substantially higher capital and margin requirements. Although
it is not possible at this time to predict whether or when Congress may act on derivatives legislation or how any
climate change bill approved by the Senate would be reconciled with ACESA, any laws or regulations that may
be adopted that subject us to additional capital or margin requirements relating to, or to additional restrictions on,
our hedging and commodity positions could have an adverse effect on our ability to hedge risks associated with
our business or on the cost of our hedging activity.
Risks Inherent in the Ownership of Our Common Units
Cash distributions are not guaranteed and may fluctuate with our performance and other external factors.
Cash distributions on our common units are not guaranteed, and depend primarily on our cash flow and our
cash on hand. Because they are not dependent on profitability, which is affected by non-cash items, our cash
distributions might be made during periods when we record losses and might not be made during periods when
we record profits.
The amount of cash we generate may fluctuate based on our performance and other factors, including:
•
•
•
the impact of the risks inherent in our business operations, as described above;
required principal and interest payments on our debt and restrictions contained in our debt instruments;
issuances of debt and equity securities;
• our ability to control expenses;
•
•
•
fluctuations in working capital;
capital expenditures; and
financial, business and other factors, a number which will be beyond our control.
Our Third Amended and Restated Agreement of Limited Partnership, as amended (“Partnership
Agreement”), gives our Board of Supervisors broad discretion in establishing cash reserves for, among other
things, the proper conduct of our business. These cash reserves will affect the amount of cash available for
distributions.
We have substantial indebtedness. Our debt agreements may limit our ability to make distributions to
unitholders, as well as our financial flexibility.
As of September 26, 2009, we had total outstanding borrowings of $350.0 million, including $250.0 million
of senior notes issued by the Partnership and our wholly-owned subsidiary, Suburban Energy Finance
Corporation, and $100.0 million of borrowings outstanding under the Operating Partnership’s revolving credit
facility. The payment of principal and interest on our debt will reduce the cash available to make distributions on
our common units. In addition, we will not be able to make any distributions to our unitholders if there is, or after
giving effect to such distribution, there would be, an event of default under the indenture governing the senior
notes. The amount of distributions that the Partnership makes to its unitholders is limited by the senior notes, and
the amount of distributions that the Operating Partnership may make to the Partnership is limited by the
revolving credit facility.
16
The revolving credit facility and the senior notes both contain various restrictive and affirmative covenants
applicable to us and the Operating Partnership, respectively, including (a) restrictions on the incurrence of
additional indebtedness, and (b) restrictions on certain liens, investments, guarantees, loans, advances, payments,
mergers, consolidations, distributions, sales of assets and other transactions. The revolving credit facility
contains certain financial covenants: (i) requiring our consolidated interest coverage ratio, as defined, to be not
less than 2.5 to 1.0 as of the end of any fiscal quarter; (ii) prohibiting our total consolidated leverage ratio, as
defined, from being greater than 4.5 to 1.0 as of the end of any fiscal quarter; and (iii) prohibiting the senior
secured consolidated leverage ratio, as defined, of the Operating Partnership from being greater than 3.0 to 1.0 as
of the end of any fiscal quarter. Under the senior note indenture, we are generally permitted to make cash
distributions equal to available cash, as defined, as of the end of the immediately preceding quarter, if no event of
default exists or would exist upon making such distributions, and our consolidated fixed charge coverage ratio, as
defined, is greater than 1.75 to 1. We and the Operating Partnership were in compliance with all covenants and
terms of the senior notes and the revolving credit facility as of September 26, 2009.
The amount and terms of our debt may also adversely affect our ability to finance future operations and
capital needs, limit our ability to pursue acquisitions and other business opportunities and make our results of
operations more susceptible to adverse economic and industry conditions. In addition to our outstanding
indebtedness, we may in the future require additional debt to finance acquisitions or for general business
purposes; however, credit market conditions may impact our ability to access such financing. If we are unable to
access needed financing or to generate sufficient cash from operations, we may be required to abandon certain
projects or curtail capital expenditures. Additional debt, where it is available, could result in an increase in our
leverage. Our ability to make principal and interest payments depends on our future performance, which is
subject to many factors, some of which are beyond our control.
Unitholders have limited voting rights.
A Board of Supervisors manages our operations. Our unitholders have only limited voting rights on matters
affecting our business, including the right to elect the members of our Board of Supervisors every three years.
It may be difficult for a third party to acquire us, even if doing so would be beneficial to our unitholders.
Some provisions of our Partnership Agreement may discourage, delay or prevent third parties from
acquiring us, even if doing so would be beneficial to our unitholders. For example, our Partnership Agreement
contains a provision, based on Section 203 of the Delaware General Corporation Law, that generally prohibits
the Partnership from engaging in a business combination with a 15% or greater unitholder for a period of three
years following the date that person or entity acquired at least 15% of our outstanding common units, unless
certain exceptions apply. Additionally, our Partnership Agreement sets forth advance notice procedures for a
unitholder to nominate a Supervisor to stand for election, which procedures may discourage or deter a potential
acquirer from conducting a solicitation of proxies to elect the acquirer’s own slate of Supervisors or otherwise
attempting to obtain control of the Partnership. These nomination procedures may not be revised or repealed, and
inconsistent provisions may not be adopted, without the approval of the holders of at least 66 2/3% of the
outstanding common units. These provisions may have an anti-takeover effect with respect to transactions not
approved in advance by our Board of Supervisors, including discouraging attempts that might result in a premium
over the market price of the common units held by our unitholders.
Unitholders may not have limited liability in some circumstances.
A number of states have not clearly established limitations on the liabilities of limited partners for the
obligations of a limited partnership. Our unitholders might be held liable for our obligations as if they were
general partners if:
•
a court or government agency determined that we were conducting business in the state but had not
17
complied with the state’s limited partnership statute; or
• unitholders’ rights to act together to remove or replace the General Partner or take other actions under
our Partnership Agreement are deemed to constitute “participation in the control” of our business for
purposes of the state’s limited partnership statute.
Unitholders may have liability to repay distributions.
Unitholders will not be liable for assessments in addition to their initial capital investment in the common
units. Under specific circumstances, however, unitholders may have to repay to us amounts wrongfully returned
or distributed to them. Under Delaware law, we may not make a distribution to unitholders if the distribution
causes our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership
interests and nonrecourse liabilities are not counted for purposes of determining whether a distribution is
permitted. Delaware law provides that a limited partner who receives a distribution of this kind and knew at the
time of the distribution that the distribution violated Delaware law will be liable to the limited partnership for the
distribution amount for three years from the distribution date. Under Delaware law, an assignee who becomes a
substituted limited partner of a limited partnership is liable for the obligations of the assignor to make
contributions to the partnership. However, such an assignee is not obligated for liabilities unknown to him at the
time he or she became a limited partner if the liabilities could not be determined from the partnership agreement.
If we issue additional limited partner interests or other equity securities as consideration for acquisitions or
for other purposes, the relative voting strength of each unitholder will be diminished over time due to the
dilution of each unitholder’s interests and additional taxable income may be allocated to each unitholder.
Our Partnership Agreement generally allows us to issue additional limited partner interests and other equity
securities without the approval of our unitholders. Therefore, when we issue additional common units or
securities ranking on a parity with the common units, each unitholder’s proportionate partnership interest will
decrease, and the amount of cash distributed on each common unit and the market price of common units could
decrease. The issuance of additional common units will also diminish the relative voting strength of each
previously outstanding common unit. In addition, the issuance of additional common units will, over time, result
in the allocation of additional taxable income, representing built-in gains at the time of the new issuance, to those
unitholders that existed prior to the new issuance.
Tax Risks to Unitholders
Our tax treatment depends on our status as a partnership for federal income tax purposes. The Internal
Revenue Service (“IRS”) could treat us as a corporation, which would substantially reduce the cash available
for distribution to unitholders.
The anticipated after-tax economic benefit of an investment in our common units depends largely on our
being treated as a partnership for federal income tax purposes. We believe that, under current law, we will be
classified as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a
ruling from the IRS on this or any other tax matter affecting us. The IRS may adopt positions that differ from the
positions we take. In addition, current law may change so as to cause us to be treated as a corporation for federal
income tax purposes or otherwise subject us to entity-level federal income taxation. Members of Congress have
proposed substantive changes to the current federal income tax laws that would affect certain publicly traded
partnerships and legislation that would eliminate partnership tax treatment for certain publicly traded
partnerships. Although no legislation is currently pending that would affect our tax treatment as a partnership, we
are unable to predict whether any such changes or other proposals will ultimately be enacted. Any modification
to the U.S. tax laws and interpretations thereof may or may not be applied retroactively. If we were treated as a
corporation for federal income tax purposes, we would be required to pay tax on our income at corporate tax
rates (currently a maximum of U.S. federal rate of 35%) and likely would be required to pay state income tax at
18
varying rates. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our
unitholders would be substantially reduced. Therefore, our treatment as a corporation would result in a material
reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial
reduction in the value of our common units. In addition, because of widespread state budget deficits and other
reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition
of state income, franchise and other forms of taxation. Any such changes could negatively impact our ability to
make distributions and also impact the value of an investment in our common units.
A successful IRS contest of the federal income tax positions we take may adversely affect the market for our
common units, and the cost of any IRS contest will reduce our cash available for distribution to our
unitholders.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal
income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions
we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the
positions we take. A court may not agree with the positions we take. Any contest with the IRS may materially
and adversely impact the market for our common units and the price at which they trade. In addition, our costs of
any contest with the IRS will be borne indirectly by our unitholders because the costs will reduce our cash
available for distribution.
A unitholder’s tax liability could exceed cash distributions on its common units.
Because our unitholders are treated as partners to whom we allocate taxable income which could be
different in amount than the cash we distribute, a unitholder is required to pay federal income taxes and, in some
cases, state and local income taxes on its allocable share of our income, even if it receives no cash distributions
from us. We cannot guarantee that a unitholder will receive cash distributions equal to its allocable share of our
taxable income or even the tax liability to it resulting from that income.
Ownership of common units may have adverse tax consequences for tax-exempt organizations and foreign
investors.
Investment in common units by certain tax-exempt entities and foreign persons raises issues specific to
them. For example, virtually all of our taxable income allocated to organizations exempt from federal income tax,
including individual retirement accounts and other retirement plans, will be unrelated business taxable income
and thus will be taxable to the unitholder. Distributions to foreign persons will be reduced by withholding taxes
at the highest applicable effective tax rate, and foreign persons will be required to file United States federal tax
returns and pay tax on their share of our taxable income. Tax-exempt entities and foreign persons should consult
their own tax advisors before investing in our common units.
There are limits on a unitholder’s deductibility of losses.
In the case of taxpayers subject to the passive loss rules (generally, individuals and closely held
corporations), any losses generated by us will only be available to offset our future income and cannot be used to
offset income from other activities, including other passive activities or investments. Unused losses may be
deducted when the unitholder disposes of its entire investment in us in a fully taxable transaction with an
unrelated party. A unitholder’s share of our net passive income may be offset by unused losses from us carried
over from prior years, but not by losses from other passive activities, including losses from other publicly-traded
partnerships.
19
The tax gain or loss on the disposition of common units could be different than expected.
A unitholder who sells common units will recognize a gain or loss equal to the difference between the
amount realized, including its share of our nonrecourse liabilities, and its adjusted tax basis in the common units.
Prior distributions in excess of cumulative net taxable income allocated to a common unit which decreased a
unitholder’s tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a
price greater than the unitholder’s tax basis in that common unit, even if the price is less than the original cost of
the common unit. A portion of the amount realized, if the amount realized exceeds the unitholder’s adjusted basis
in that common unit, will likely be characterized as ordinary income. Furthermore, should the IRS successfully
contest some conventions used by us, a unitholder could recognize more gain on the sale of common units than
would be the case under those conventions, without the benefit of decreased income in prior years.
Reporting of partnership tax information is complicated and subject to audits.
We furnish each unitholder with a Schedule K-1 that sets forth its allocable share of income, gains, losses
and deductions. In preparing these schedules, we use various accounting and reporting conventions and adopt
various depreciation and amortization methods. We cannot guarantee that these conventions will yield a result
that conforms to statutory or regulatory requirements or to administrative pronouncements of the IRS. Further,
our income tax return may be audited, which could result in an audit of a unitholder’s income tax return and
increased liabilities for taxes because of adjustments resulting from the audit.
We treat each purchaser of our common units as having the same tax benefits without regard to the actual
common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the
common units.
Because we cannot match transferors and transferees of common units and because of other reasons,
uniformity of the economic and tax characteristics of the common units to a purchaser of common units of the
same class must be maintained. To maintain uniformity and for other reasons, we have adopted certain
depreciation and amortization conventions which may be inconsistent with Treasury Regulations. A successful
IRS challenge to those positions could adversely affect the amount of tax benefits available to a unitholder. It
also could affect the timing of these tax benefits or the amount of gain from the sale of common units, and could
have a negative impact on the value of our common units or result in audit adjustments to a unitholder’s income
tax return.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units
each month based upon the ownership of our units on the first day of each month, instead of on the basis of
the date a particular unit is transferred. The IRS may challenge this treatment, which could change the
allocation of items of income, gain, loss and deduction among our unitholders.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units
each month based upon the ownership of our units on the first day of each month, instead of on the basis of the
date a particular unit is transferred. The use of this proration method may not be permitted under existing
Treasury Regulations. If the IRS were to challenge this method or new Treasury Regulations were issued, we
may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
Unitholders may have negative tax consequences if we default on our debt or sell assets.
If we default on any of our debt obligations, our lenders will have the right to sue us for non-payment. This
could cause an investment loss and negative tax consequences for unitholders through the realization of taxable
income by unitholders without a corresponding cash distribution. Likewise, if we were to dispose of assets and
realize a taxable gain while there is substantial debt outstanding and proceeds of the sale were applied to the
debt, unitholders could have increased taxable income without a corresponding cash distribution.
20
The sale or exchange of 50% or more of our common units during any twelve-month period will result in a
deemed termination (and reconstitution) of the Partnership for federal income tax purposes which would
cause unitholders to be allocated an increased amount of taxable income.
We will be deemed to have terminated (and reconstituted) for federal income tax purposes if there is a sale
or exchange of 50% or more of the total interests in our common units within a twelve-month period. Were this
to occur, it would, among other things, result in the closing of our taxable year for all unitholders and could result
in a deferral of depreciation deductions allowable in computing our taxable income. This would result in
unitholders being allocated an increased amount of taxable income.
There are state, local and other tax considerations for our unitholders.
In addition to United States federal income taxes, unitholders will likely be subject to other taxes, such as
state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed
by the various jurisdictions in which we do business or own property, even if the unitholder does not reside in
any of those jurisdictions. A unitholder will likely be required to file state and local income tax returns and pay
state and local income taxes in some or all of the various jurisdictions in which we do business or own property
and may be subject to penalties for failure to comply with those requirements. It is the responsibility of each
unitholder to file all United States federal, state and local income tax returns that may be required of such
unitholder.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
As of September 26, 2009, we owned approximately 75% of our customer service center and satellite locations
and leased the balance of our retail locations from third parties. We own and operate a 22 million gallon
refrigerated, aboveground propane storage facility in Elk Grove, California. Additionally, we own our principal
executive offices located in Whippany, New Jersey.
The transportation of propane requires specialized equipment. The trucks and railroad tank cars utilized for this
purpose carry specialized steel tanks that maintain the propane in a liquefied state. As of September 26, 2009, we
had a fleet of 8 transport truck tractors, of which we owned two, and 23 railroad tank cars, of which we owned none.
In addition, as of September 26, 2009 we had 773 bobtail and rack trucks, of which we owned approximately 40%,
112 fuel oil tankwagons, of which we owned approximately 39%, and 1,051 other delivery and service vehicles, of
which we owned approximately 49%. We lease the vehicles we do not own. As of September 26, 2009, we also
owned approximately 717,751 customer propane storage tanks with typical capacities of 100 to 500 gallons,
150,839 customer propane storage tanks with typical capacities of over 500 gallons and 257,479 portable propane
cylinders with typical capacities of five to ten gallons.
ITEM 3. LEGAL PROCEEDINGS
Litigation
Our operations are subject to all operating hazards and risks normally incidental to handling, storing and
delivering combustible liquids such as propane. As a result, we have been, and will continue to be, a defendant in
various legal proceedings and litigation arising in the ordinary course of business. We are self-insured for general
21
and product, workers’ compensation and automobile liabilities up to predetermined amounts above which third
party insurance applies. We believe that the self-insured retentions and coverage we maintain are reasonable and
prudent. Although any litigation is inherently uncertain, based on past experience, the information currently
available to us, and the amount of our self-insurance reserves for known and unasserted self-insurance claims
(which was approximately $52.2 million at September 26, 2009), we do not believe that these pending or
threatened litigation matters, or known claims or known contingent claims, will have a material adverse effect on
our results of operations, financial condition or cash flow. For the portion of our estimated self-insurance
liability that exceeds our deductibles, we record a corresponding asset related to the amount of the liability
covered by insurance (which was approximately $14.8 million at September 26, 2009).
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The 2009 Tri-Annual Meeting of the Partnership’s Unitholders (the “Tri-Annual Meeting”) was held on July
22, 2009. At the Tri-Annual Meeting, the Unitholders re-elected to the Board of Supervisors, for a three-year term,
all six nominees proposed by the Board:
Nominee
Harold R. Logan, Jr.
John Hoyt Stookey
Dudley C. Mecum
John D. Collins
Jane Swift
Michael J. Dunn, Jr.
For
30,441,054
30,301,633
30,320,031
30,166,800
30,378,578
30,415,930
Withheld
838,790
978,211
959,813
1,113,044
901,266
863,914
At the Tri-Annual Meeting, the Unitholders also approved the following proposals:
Adoption of the Partnership’s 2009 Restricted Unit Plan, including the authorization of 1,200,000 Common
Units to be available for grant under the plan:
For
15,829,007
Against
2,251,830
Abstain
578,168
Broker
Non-Votes
12,620,839
Adjournment of the Tri-Annual Meeting, if necessary, to solicit additional proxies:
For
28,923,408
Against
1,726,994
Abstain
626,942
Broker
Non-Votes
2,500
22
PART II
ITEM 5. MARKET FOR THE REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER
MATTERS AND ISSUER PURCHASES OF UNITS
(a) Our Common Units, representing limited partner interests in the Partnership, are listed and traded on the
New York Stock Exchange (“NYSE”) under the symbol SPH. As of November 23, 2009, there were 745
Common Unitholders of record. The following table presents, for the periods indicated, the high and low sales
prices per Common Unit, as reported on the NYSE, and the amount of quarterly cash distributions declared and
paid per Common Unit in respect of each quarter.
Fiscal 2009
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
Fiscal 2008
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
Common Unit Price Range
High
Low
$
35.46
41.60
42.98
46.41
$
20.40
31.00
35.81
39.79
Cash Distribution
Declared per
Common Unit
$
0.8100
0.8150
0.8250
0.8300
$
48.50
42.43
42.60
39.59
$
40.00
34.00
37.88
33.13
$
0.7625
0.7750
0.8000
0.8050
We make quarterly distributions to our partners in an aggregate amount equal to our Available Cash (as
defined in our Partnership Agreement as adopted effective October 19, 2006, as amended) with respect to such
quarter. Available Cash generally means all cash on hand at the end of the fiscal quarter plus all additional cash
on hand as a result of borrowings subsequent to the end of such quarter less cash reserves established by the
Board of Supervisors in its reasonable discretion for future cash requirements.
We are a publicly traded limited partnership and, other than certain corporate subsidiaries, we are not subject
to federal income tax. Instead, Unitholders are required to report their allocable share of our earnings or loss,
regardless of whether we make distributions.
(b) Not applicable.
(c) None.
23
ITEM 6. SELECTED FINANCIAL DATA
The following table presents our selected consolidated historical financial data as derived from our audited
consolidated financial statements, certain of which are included elsewhere in this Annual Report. All amounts in
the table below, except per unit data, are in thousands.
Statement of Operations Data
Revenues
Costs and expenses
Restructuring charges and severance costs (b)
Impairment of goodwill (c)
Income before interest expense, loss on debt
extinguishment and provision for income taxes (d)
Interest expense, net
Loss on debt extinguishment (e)
Provision for income taxes
Income (loss) from continuing operations (d)
Discontinued operations:
Gain on disposal of discontinued operations (f)
Income from discontinued operations
Net income (loss)
Income (loss) from continuing operations per Common
Unit - basic
Net income (loss) per Common Unit - basic (g)
Net income (loss) per Common Unit - diluted (g)
Cash distributions declared per unit
Balance Sheet Data (end of period)
Cash and cash equivalents
Current assets
Total assets
Current liabilities, excluding short-term borrowings
and current portion of long-term borrowings
Total debt
Other long-term liabilities
Partners' capital - Common Unitholders
Partner's (deficit) capital - General Partner
Statement of Cash Flows Data
Cash provided by (used in)
Operating activities
Investing activities
Financing activities
September
26, 2009
September
27, 2008
Year Ended
September
29, 2007
September
30, 2006 (a)
September
24, 2005
$
1,143,154
932,539
-
-
$
1,574,163
1,424,035
-
-
$
1,439,563
1,273,482
1,485
-
$
1,657,130
1,521,316
6,076
-
$
1,615,555
1,546,531
2,775
656
210,615
38,267
4,624
2,486
165,238
-
-
165,238
150,128
37,052
-
1,903
111,173
43,707
-
154,880
164,596
35,596
-
5,653
123,347
1,887
2,053
127,287
129,738
40,680
-
764
88,294
-
2,446
90,740
65,593
40,374
36,242
803
(11,826)
976
2,774
(8,076)
4.99
4.99
4.96
3.26
$
3.39
4.72
4.70
3.09
$
3.79
3.91
3.89
2.76
$
2.76
2.84
2.83
2.48
$
(0.38)
(0.26)
(0.26)
2.45
$
$
163,173
307,556
977,514
$
137,698
359,551
1,035,713
$
96,586
295,940
988,947
$
60,571
236,027
945,566
$
14,411
236,803
959,305
180,059
349,415
88,323
421,005
$
-
226,056
531,772
57,809
264,231
$
-
206,011
548,538
68,121
208,230
$
-
191,195
548,304
105,366
170,151
(1,969)
$
193,851
575,295
114,043
159,199
(1,779)
$
$
$
246,551
(16,852)
(204,224)
$
$
120,517
36,630
(116,035)
$
$
145,957
(19,689)
(90,253)
$
$
170,321
(19,092)
(105,069)
$
$
39,005
(24,631)
(53,444)
Other Data
Depreciation and amortization - continuing operations
Depreciation and amortization - discontinued operations
EBITDA (h)
Adjusted EBITDA (h)
Capital expenditures - maintenance and growth (i)
Retail gallons sold
Propane
Fuel oil and refined fuels
$
30,343
-
236,334
234,621
21,837
$
28,394
-
222,229
220,465
21,819
$
28,790
452
197,778
205,333
26,756
$
32,653
498
165,335
150,863
23,057
$
37,260
502
70,863
68,366
29,301
343,894
57,381
386,222
76,515
432,526
104,506
466,779
145,616
516,040
244,536
24
(a) Fiscal 2006 includes 53 weeks of operations compared to 52 weeks in each of fiscal 2009, 2008, 2007 and
2005.
(b) During fiscal 2007, we incurred $1.5 million in charges associated with severance for positions eliminated
unrelated to any specific plan of restructuring. During fiscal 2006, we incurred $6.1 million in restructuring
charges associated primarily with severance costs from our field realignment efforts initiated during the fourth
quarter of fiscal 2005, including the restructuring of our services business. During fiscal 2005, we incurred $2.8
million in restructuring charges associated primarily with severance costs from the realignment of our field
operations.
(c) During fiscal 2005, we recorded a non-cash charge of $0.7 million related to the impairment of goodwill in our
all other category.
(d) These amounts include gains from the disposal of property, plant and equipment of $0.7 million for fiscal
2009, $2.3 million for fiscal 2008, $2.8 million for fiscal 2007, $1.0 million for fiscal 2006 and $2.0 million
for fiscal 2005.
(e) During fiscal 2009, we purchased $175.0 million aggregate principal amount of the 2003 Senior Notes
through a cash tender offer. In connection with the tender offer, we recognized a loss on the extinguishment
of debt of $4.6 million in the fourth quarter of fiscal 2009, consisting of $2.8 million for the tender premium
and related fees, as well as the write-off of $1.8 million in unamortized debt origination costs and
unamortized discount. During fiscal 2005, we incurred a charge of $36.2 million as a result of our March 31,
2005 debt refinancing to reflect the loss on debt extinguishment associated with a prepayment premium of
$32.0 million and the write-off of $4.2 million of unamortized bond issuance costs associated with the
previously outstanding senior notes.
(f) Gain on disposal of discontinued operations for fiscal 2008 of $43.7 million reflects the October 2, 2007 sale
of our Tirzah, South Carolina underground granite propane storage cavern, and associated 62-mile pipeline,
for $53.7 million in net proceeds (the “Tirzah Sale”). Gain on disposal of discontinued operations for fiscal
2007 of $1.9 million reflects the exchange, in a non-cash transaction, of nine non-strategic customer service
centers for three customer service centers of another company in Alaska, as well as the sale of three
additional customer service centers for net cash proceeds of $1.3 million. Gain on disposal of discontinued
operations for fiscal 2005 of $1.0 million reflects the finalization of certain purchase price adjustments with
the buyer of the customer service centers sold during fiscal 2004. The gains on disposal have been
accounted for within discontinued operations. Prior period results of operations attributable to the customer
service centers sold during fiscal 2007 were not significant and, as such, prior period results were not
reclassified to remove financial results from continuing operations. The prior period results of operations
attributable to the sale of our Tirzah, South Carolina storage cavern and associated pipeline have been
reclassified to remove financial results from continuing operations.
(g) Computations of basic earnings per Common Unit for the years ended September 26, 2009, September 27,
2008 and September 29, 2007 were performed by dividing net income by the weighted average number of
outstanding Common Units, and restricted units granted under our restricted unit plans to retirement-eligible
grantees. For fiscal 2006, earnings per Common Unit were performed using the two-class method when
participating securities exist, as applicable. The two-class method is an earnings allocation formula that
computes earnings per unit for each class of Common Unit and participating security according to
distributions declared and participating rights in undistributed earnings, as if all of the earnings were
distributed to the limited partners and the General Partner (inclusive of the previously outstanding IDRs of
the General Partner which were considered participating securities for purposes of the two-class method).
Net income was allocated to the Common Unitholders and the General Partner in accordance with their
respective partnership ownership interests, after giving effect to any priority income allocations for IDRs of
the General Partner. As a result of the GP Exchange Transaction on October 19, 2006, the two-class method
25
of computing income per Common Unit under is no longer applicable.
The requirements of the two-class method do not apply to the computation of earnings per Common Unit in
periods in which a net loss is reported and therefore did not have any impact on loss per Common Unit for
the year ended September 24, 2005. Application of the two-class method had a dilutive effect on income per
Common Unit of $0.07 for the year ended September 30, 2006. Basic net loss per Common Unit for the year
ended September 24, 2005 was computed by dividing net loss, after deducting our General Partner’s interest,
by the weighted average number of outstanding Common Units, and restricted units granted under our
restricted unit plans to retirement-eligible grantees. Diluted net loss per Common Unit for the same period
was computed by dividing net loss, after deducting our General Partner’s interest, by the weighted average
number of outstanding Common Units and unvested restricted units under our restricted unit plans. For
purposes of the computation of income per Common Unit for the year ended September 29, 2007, earnings
that would have been allocated to the General Partner for the period prior to the GP Exchange Transaction
were not significant.
(h) EBITDA represents net income before deducting interest expense, income taxes, depreciation and
amortization. Adjusted EBITDA represents EBITDA excluding the unrealized net gain or loss on mark-to-
market activity for derivative instruments. Our management uses EBITDA and Adjusted EBITDA as
measures of liquidity and we are including them because we believe that they provide our investors and
industry analysts with additional information to evaluate our ability to meet our debt service obligations and
to pay our quarterly distributions to holders of our Common Units. In addition, certain of our incentive
compensation plans covering executives and other employees utilize Adjusted EBITDA as the performance
target. Moreover, our revolving credit agreement requires us to use Adjusted EBITDA as a component in
calculating our leverage and interest coverage ratios. EBITDA and Adjusted EBITDA are not recognized
terms under generally accepted accounting principles (“GAAP”) and should not be considered as an
alternative to net income or net cash provided by operating activities determined in accordance with GAAP.
Because EBITDA and Adjusted EBITDA as determined by us excludes some, but not all, items that affect
net income, they may not be comparable to EBITDA and Adjusted EBITDA or similarly titled measures used
by other companies.
The following table sets forth (i) our calculations of EBITDA and Adjusted EBITDA and (ii) a reconciliation
of EBITDA and Adjusted EBITDA, as so calculated, to our net cash provided by operating activities
(amounts in thousands):
26
Net income (loss)
Add:
Provision for income taxes
Interest expense, net
Depreciation and amortization
Continuing operations
Discontinued operations
EBITDA
Unrealized (non-cash) (gains) losses on
changes in fair value of derivatives
Adjusted EBITDA
Add (subtract):
Provision for income taxes - current
Interest expense, net
Loss on debt extinguishment
Unrealized (non-cash) gains (losses) on
changes in fair value of derivatives
Compensation cost recognized under
Restricted Unit Plan
Gain on disposal of property, plant and
equipment, net
Gain on disposal of
discontinued operations
Pension settlement charge
Changes in working capital and other
assets and liabilities
Fiscal
2009
Fiscal
2008
Fiscal
2007
Fiscal
2006
Fiscal
2005
$
165,238
$
154,880
$
127,287
$
90,740
$
(8,076)
2,486
38,267
30,343
-
236,334
(1,713)
234,621
(1,101)
(38,267)
4,624
1,713
2,396
1,903
37,052
28,394
-
222,229
(1,764)
220,465
(626)
(37,052)
-
1,764
2,156
5,653
35,596
28,790
452
197,778
7,555
205,333
(1,853)
(35,596)
-
764
40,680
32,653
498
165,335
(14,472)
150,863
(764)
(40,680)
-
(7,555)
14,472
3,014
2,221
803
40,374
37,260
502
70,863
(2,497)
68,366
(803)
(40,374)
36,242
2,497
1,805
(650)
(2,252)
(2,782)
(1,000)
(2,043)
-
-
(43,707)
-
(1,887)
3,269
-
4,437
(976)
-
43,215
(20,231)
(15,986)
40,772
(25,709)
Net cash provided by operating activities
$
246,551
$
120,517
$
145,957
$
170,321
$
39,005
(i) Our capital expenditures fall generally into two categories: (i) maintenance expenditures, which include
expenditures for repair and replacement of property, plant and equipment; and (ii) growth capital expenditures
which include new propane tanks and other equipment to facilitate expansion of our customer base and
operating capacity.
27
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following is a discussion of our financial condition and results of operations, which should be read in
conjunction with our consolidated financial statements and notes thereto included elsewhere in this Annual Report.
Executive Overview
The following are factors that regularly affect our operating results and financial condition. In addition, our
business is subject to the risks and uncertainties described in Item 1A of this Annual Report.
Product Costs and Supply
The level of profitability in the retail propane, fuel oil, natural gas and electricity businesses is largely
dependent on the difference between retail sales price and product cost. The unit cost of our products,
particularly propane, fuel oil and natural gas, is subject to volatility as a result of product supply or other market
conditions, including, but not limited to, economic and political factors impacting crude oil and natural gas
supply or pricing. We enter into product supply contracts that are generally one-year agreements subject to
annual renewal, and we also purchase product on the open market. We attempt to reduce our exposure to volatile
product costs by short-term pricing arrangements, rather than long-term fixed price supply arrangements. Our
propane supply contracts typically provide for pricing based upon index formulas using the posted prices
established at major supply points such as Mont Belvieu, Texas, or Conway, Kansas (plus transportation costs) at
the time of delivery.
To supplement our annual purchase requirements, we may utilize forward fixed price purchase contracts to
acquire a portion of the propane that we resell to our customers, which allows us to manage our exposure to
unfavorable changes in commodity prices and to assure adequate physical supply. The percentage of contract
purchases, and the amount of supply contracted for under forward contracts at fixed prices, will vary from year to
year based on market conditions.
Product cost changes can occur rapidly over a short period of time and can impact profitability. There is no
assurance that we will be able to pass on product cost increases fully or immediately, particularly when product
costs increase rapidly. Therefore, average retail sales prices can vary significantly from year to year as product
costs fluctuate with propane, fuel oil, crude oil and natural gas commodity market conditions. In addition, in
periods of sustained higher commodity prices, as has been experienced over the past several fiscal years, retail
sales volumes have been negatively impacted by customer conservation efforts.
Seasonality
The retail propane and fuel oil distribution businesses, as well as the natural gas marketing business, are
seasonal because of the primary use for heating in residential and commercial buildings. Historically,
approximately two-thirds of our retail propane volume is sold during the six-month peak heating season from
October through March. The fuel oil business tends to experience greater seasonality given its more limited use
for space heating and approximately three-fourths of our fuel oil volumes are sold between October and March.
Consequently, sales and operating profits are concentrated in our first and second fiscal quarters. Cash flows
from operations, therefore, are greatest during the second and third fiscal quarters when customers pay for
product purchased during the winter heating season. We expect lower operating profits and either net losses or
lower net income during the period from April through September (our third and fourth fiscal quarters). To the
extent necessary, we will reserve cash from the second and third quarters for distribution to holders of our
Common Units in the first and fourth fiscal quarters.
28
Weather
Weather conditions have a significant impact on the demand for our products, in particular propane, fuel oil
and natural gas, for both heating and agricultural purposes. Many of our customers rely heavily on propane, fuel
oil or natural gas as a heating source. Accordingly, the volume sold is directly affected by the severity of the
winter weather in our service areas, which can vary substantially from year to year. In any given area, sustained
warmer than normal temperatures will tend to result in reduced propane, fuel oil and natural gas consumption,
while sustained colder than normal temperatures will tend to result in greater consumption.
Hedging and Risk Management Activities
We engage in hedging and risk management activities to reduce the effect of price volatility on our product
costs and to ensure the availability of product during periods of short supply. We enter into propane forward and
option agreements with third parties, and use fuel oil and crude oil futures and option contracts traded on the
New York Mercantile Exchange (“NYMEX”), to purchase and sell fuel oil and crude oil at fixed prices in the
future. The majority of the futures, forward and option agreements are used to hedge price risk associated with
propane and fuel oil physical inventory, as well as, in certain instances, forecasted purchases of propane or fuel
oil. Forward contracts are generally settled physically at the expiration of the contract and futures are generally
settled in cash at the expiration of the contract. Although we use derivative instruments to reduce the effect of
price volatility associated with priced physical inventory and forecasted transactions, we do not use derivative
instruments for speculative trading purposes. Risk management activities are monitored by an internal
Commodity Risk Management Committee, made up of five members of management and reporting to our Audit
Committee, through enforcement of our Hedging and Risk Management Policy.
Under our hedging and risk management strategy, realized gains or losses on futures or option contracts will
typically offset losses or gains on the physical inventory once the product is sold to customers at market prices.
However, as a result of lower than expected volumes primarily attributable to customer conservation, we realized
losses under certain futures positions in fiscal 2008 that were not fully offset by sales of the physical product.
Accordingly, our risk management activities had a negative effect on earnings of approximately $10.8 million
during fiscal 2008 as a result of realized losses on futures contracts that were not fully offset by sales of physical
product. See Item 7A of this Annual Report for a further discussion of risk management activities.
Critical Accounting Policies and Estimates
Our significant accounting policies are summarized in Note 2, “Summary of Significant Accounting
Policies,” included within the Notes to Consolidated Financial Statements section elsewhere in this Annual
Report.
Certain amounts included in or affecting our consolidated financial statements and related disclosures must
be estimated, requiring management to make certain assumptions with respect to values or conditions that cannot
be known with certainty at the time the financial statements are prepared. The preparation of financial
statements in conformity with generally accepted accounting principles (“GAAP”) requires management to make
estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent
assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses
during the reporting period. We are also subject to risks and uncertainties that may cause actual results to differ
from estimated results. Estimates are used when accounting for depreciation and amortization of long-lived
assets, employee benefit plans, self-insurance and litigation reserves, environmental reserves, allowances for
doubtful accounts, asset valuation assessments and valuation of derivative instruments. We base our estimates
on historical experience and on various other assumptions that are believed to be reasonable under the
circumstances, the results of which form the basis for making judgments about the carrying values of assets and
liabilities that are not readily apparent from other sources. Any effects on our business, financial position or
results of operations resulting from revisions to these estimates are recorded in the period in which the facts that
29
give rise to the revision become known to us. Management has reviewed these critical accounting estimates and
related disclosures with the Audit Committee of our Board of Supervisors. We believe that the following are our
critical accounting estimates:
Allowances for Doubtful Accounts. We maintain allowances for doubtful accounts for estimated losses
resulting from the inability of our customers to make required payments. We estimate our allowances for
doubtful accounts using a specific reserve for known or anticipated uncollectible accounts, as well as an
estimated reserve for potential future uncollectible accounts taking into consideration our historical write-offs. If
the financial condition of one or more of our customers were to deteriorate resulting in an impairment in their
ability to make payments, additional allowances could be required. As a result of our large customer base, which
is comprised of approximately 850,000 customers, no individual customer account is material. Therefore, while
some variation to actual results occurs, historically such variability has not been material. Schedule II, Valuation
and Qualifying Accounts, provides a summary of the changes in our allowances for doubtful accounts during the
period.
Pension and Other Postretirement Benefits. We estimate the rate of return on plan assets, the discount rate used
to estimate the present value of future benefit obligations and the expected cost of future health care benefits in
determining our annual pension and other postretirement benefit costs. While we believe that our assumptions
are appropriate, significant differences in our actual experience or significant changes in market conditions may
materially affect our pension and other postretirement benefit obligations and our future expense. See “Liquidity
and Capital Resources - Pension Plan Assets and Obligations” below for additional disclosure regarding pension
benefits.
With other assumptions held constant, an increase of 100 basis points in the discount rate would have an
estimated favorable impact of $0.2 million on net pension and postretirement benefit costs and an increase of
100 basis points in the expected rate of return assumption would have an estimated favorable impact of
$1.2 million on net pension benefit costs. With other assumptions held constant, a decrease of 100 basis points
in the discount rate would have an estimated unfavorable impact of $0.2 million on net pension and
postretirement benefit costs and a decrease of 100 basis points in the expected rate of return assumption would
have an estimated unfavorable impact of $1.2 million on net pension benefit costs.
Self-Insurance Reserves. Our accrued self-insurance reserves represent the estimated costs of known and
anticipated or unasserted claims under our general and product, workers’ compensation and automobile
insurance policies. Accrued insurance provisions for unasserted claims arising from unreported incidents are
based on an analysis of historical claims data. For each unasserted claim, we record a self-insurance provision
up to the estimated amount of the probable claim utilizing actuarially determined loss development factors
applied to actual claims data. Our self-insurance provisions are susceptible to change to the extent that actual
claims development differs from historical claims development. We maintain insurance coverage wherein our
net exposure for insured claims is limited to the insurance deductible, claims above which are paid by our
insurance carriers. For the portion of our estimated self-insurance liability that exceeds our deductibles, we
record an asset related to the amount of the liability expected to be paid by the insurance companies.
Historically, we have not experienced significant variability in our actuarial estimates for claims incurred but not
reported. Accrued insurance provisions for reported claims are reviewed at least quarterly, and our assessment of
whether a loss is probable and/or reasonably estimable is updated as necessary. Due to the inherently uncertain
nature of, in particular, product liability claims, the ultimate loss may differ materially from our estimates.
However, because of the nature of our insurance arrangements, those material variations historically have not,
nor are they expected in the future to have, a material impact on our results of operations or financial position.
30
Results of Operations and Financial Condition
Net income for fiscal 2009 amounted to $165.2 million, or $4.99 per Common Unit, an increase of $10.3
million, or 6.6%, compared to net income of $154.9 million, or $4.72 per Common Unit, in fiscal 2008. Earnings
before interest, taxes, depreciation and amortization (“EBITDA”) increased $14.1 million, or 6.3%, to $236.3
million in fiscal 2009 compared to $222.2 million for fiscal 2008. Net income and EBITDA for fiscal 2009
included a loss on debt extinguishment of $4.6 million associated with the debt tender offer completed during the
fourth quarter of fiscal 2009. Net income and EBITDA for fiscal 2008 included a gain (reported within
discontinued operations) of $43.7 million from the sale of our Tirzah, South Carolina underground propane
storage cavern and associated 62-mile pipeline. Therefore, excluding the effects of these significant items on our
earnings for both periods, EBITDA increased $62.4 million, or 35.0%, in fiscal 2009 compared to the prior year.
In addition to the increased earnings, fiscal 2009 included several notable achievements, including: (i) a
$185 million reduction in total debt; (ii) the refinancing of our revolving credit facility to a new four-year facility
on favorable terms relative to an otherwise challenging credit market; (iii) an upgrade to our credit ratings by
both Moody’s Investors Service and Standard & Poor’s; (iv) the successful issuance of 2,430,934 Common
Units, the proceeds of which were used to fund a portion of the debt reduction; and, (v) an increase of $0.10 per
Common Unit, or 3.1%, in the annualized distribution rate compared to the end of fiscal 2008. We ended fiscal
2009 with $163.2 million of cash on hand, an increase of $25.5 million compared to the end of fiscal 2008,
despite the use of cash for a portion of the debt reduction.
Revenues of $1,143.2 million decreased $431.0 million, or 27.4%, compared to $1,574.2 million in the prior
year, primarily as a result of a decline in average selling prices associated with lower commodity prices and, to a
lesser extent, lower sales volumes. Retail propane gallons sold for fiscal 2009 decreased 42.3 million gallons, or
11.0%, to 343.9 million gallons from 386.2 million gallons in fiscal 2008. Sales of fuel oil and other refined fuels
decreased 19.1 million gallons, or 25.0%, to 57.4 million gallons compared to 76.5 million gallons in the prior
year. Overall average temperatures in our service territories for fiscal 2009 were 5% colder than the prior year.
The favorable volume impact from the colder average temperatures was more than offset by declines in
commercial and industrial volumes resulting from the recession and, to a lesser extent, continued customer
conservation.
In the commodities markets, average posted prices for propane and fuel oil during fiscal 2009 were 51.7%
and 46.1% lower, respectively, compared to fiscal 2008. Cost of products sold declined $499.0 million, or 48.0%,
to $540.4 million in fiscal 2009 compared to $1,039.4 million in the prior year. The sharp decline in commodity
prices, particularly during the first half of fiscal 2009, compared to the historically high commodity prices
reached during fiscal 2008, resulted in a reduction in product costs that outpaced the decline in average selling
prices. In addition, during fiscal 2008 we reported realized losses from risk management activities that were not
fully offset by sales of the physical product, resulting in a $10.8 million reduction to cost of products sold in
fiscal 2009 compared to the prior year. Cost of products sold for fiscal 2009 and fiscal 2008 included a $1.7
million and $1.8 million unrealized (non-cash) gain, respectively, attributable to the mark-to-market adjustment
for derivative instruments used in risk management activities.
Combined operating and general and administrative expenses of $361.8 million increased $5.6 million, or
1.6%, compared to $356.2 million in the prior year, primarily due to higher variable compensation associated
with higher earnings, partially offset by continued savings in payroll and vehicle expenses attributable to further
operating efficiencies and lower diesel costs, as well as lower bad debt expense.
Net interest expense increased $1.2 million, or 3.2%, to $38.3 million in fiscal 2009 compared to $37.1
million in fiscal 2008 as a result of lower interest income earned on invested cash. With the $175 million debt
tender offer which was completed on September 9, 2009, we have reduced our interest expense requirement by
approximately $12.0 million on an annualized basis beginning in fiscal 2010. As has been the case since April
2006, during fiscal 2009 there were no borrowings under our revolving credit facility to support working capital
31
needs, as such needs continue to be funded from cash on hand.
As we look ahead to fiscal 2010, our anticipated cash requirements include: (i) maintenance and growth capital
expenditures of approximately $25.0 million; (ii) approximately $28.1 million of interest and income tax payments;
and (iii) assuming distributions remain at the current level, approximately $117.2 million of distributions to
Common Unitholders. Based on our current cash position, availability under the Revolving Credit Agreement
(unused borrowing capacity of $92.8 million at September 26, 2009) and expected cash flow from operating
activities, we expect to have sufficient funds to meet our current and future obligations. Based on our current
forecast of working capital requirements for fiscal 2010, we currently do not expect to borrow under our credit
facility to fund those requirements.
Fiscal Year 2009 Compared to Fiscal Year 2008
Revenues
(Dollars in thousands)
Revenues
Propane
Fuel oil and refined fuels
Natural gas and electricity
All other
Total revenues
Fiscal
2009
Fiscal
2008
(Decrease)
Percent
(Decrease)
$
864,012
159,596
76,832
42,714
1,143,154
$
$
1,132,950
288,078
103,745
49,390
1,574,163
$
$
(268,938)
(128,482)
(26,913)
(6,676)
(431,009)
$
(23.7%)
(44.6%)
(25.9%)
(13.5%)
(27.4%)
Total revenues decreased $431.0 million, or 27.4%, to $1,143.2 million for the year ended September 26,
2009 compared to $1,574.2 million for the year ended September 27, 2008, due to a combination of lower
volumes and lower average selling prices associated with lower product costs. Volumes for the fiscal 2009 were
lower than the prior year due to the negative impact of adverse economic conditions, particularly on our
commercial and industrial accounts, as well as ongoing customer conservation, partially offset by the favorable
impact of colder temperatures. From a weather perspective, average heating degree days, as reported by the
National Oceanic and Atmospheric Administration) in our service territories were 99% of normal for fiscal 2009
and 5% colder compared to the prior year.
Revenues from the distribution of propane and related activities of $864.0 million for the year ended
September 26, 2009 decreased $268.9 million, or 23.7%, compared to $1,133.0 million for the year ended
September 27, 2008, primarily due to lower average selling prices, as well as lower volumes in our commercial
and industrial accounts and, to a lesser extent, our residential accounts. Retail propane gallons sold in fiscal 2009
decreased 42.3 million gallons, or 11.0%, to 343.9 million gallons from 386.2 million gallons in the prior year.
The average propane selling prices during fiscal 2009 decreased approximately 14.0% compared to the prior year
due to lower product costs, thereby having a negative impact on revenues. Additionally, revenues from wholesale
and other propane activities of $43.4 million for the year ended September 26, 2009 decreased $18.3 million
compared to the prior year.
Revenues from the distribution of fuel oil and refined fuels of $159.6 million for the year ended September
26, 2009 decreased $128.5 million, or 44.6%, from $288.1 million in the prior year, primarily due to lower
volumes and lower average selling prices. Fuel oil and refined fuels gallons sold in fiscal 2009 decreased 19.1
million gallons, or 25.0%, to 57.4 million gallons from 76.5 million gallons in the prior year. Lower volumes in
our fuel oil and refined fuels segment were primarily attributable to the impact of ongoing customer conservation
driven by adverse economic conditions and continued high energy prices relative to historical averages. The
32
average fuel oil and refined fuels selling prices during fiscal 2009 decreased approximately 26.9% compared to
the prior year due to lower product costs, thereby having a negative impact on revenues.
Revenues in our natural gas and electricity segment decreased $26.9 million, or 25.9%, to $76.8 million for
the year ended September 26, 2009 compared to $103.7 million in the prior year as a result of lower average
selling prices and lower volumes. Revenues in our all other segment decreased 13.5% to $42.7 million in fiscal
2009 from $49.4 million in the prior year, primarily due to reduced installation service activities as a result of the
market decline in residential and commercial construction and other adverse economic conditions.
Cost of Products Sold
(Dollars in thousands)
Cost of products sold
Propane
Fuel oil and refined fuels
Natural gas and electricity
All other
Total cost of products sold
Fiscal
2009
Fiscal
2008
(Decrease)
Percent
(Decrease)
$
$
367,016
104,634
57,216
11,519
540,385
$
689,921
247,310
87,600
14,605
1,039,436
$
$
(322,905)
(142,676)
(30,384)
(3,086)
(499,051)
$
(46.8%)
(57.7%)
(34.7%)
(21.1%)
(48.0%)
As a percent of total revenues
47.3%
66.0%
The cost of products sold reported in the consolidated statements of operations represents the weighted
average unit cost of propane and fuel oil sold, as well as the cost of natural gas and electricity, including
transportation costs to deliver product from our supply points to storage or to our customer service centers. Cost
of products sold also includes the cost of appliances and related parts sold or installed by our customer service
centers computed on a basis that approximates the average cost of the products. Unrealized (non-cash) gains or
losses from changes in the fair value of derivative instruments that are not designated as cash flow hedges are
recorded within cost of products sold. Cost of products sold excludes depreciation and amortization; these
amounts are reported separately within the consolidated statements of operations.
Cost of products sold decreased $499.0 million, or 48.0%, to $540.4 million for the year ended September
26, 2009 compared to $1,039.4 million in the prior year due to the impact of the decline in product costs, lower
volumes sold and the favorable impact from our risk management activities (during fiscal 2008 we reported
realized losses from risk management activities that were not fully offset by sales of the physical product,
resulting in a $10.8 million reduction to cost of products sold in fiscal 2009 compared to the prior year). Cost of
products sold in fiscal 2009 and fiscal 2008 included a $1.7 million and $1.8 million unrealized (non-cash) gain,
respectively, representing the net change in the fair value of derivative instruments during the period ($3.1
million increase in cost of products sold reported within the propane segment, offset by a $3.0 million decrease
in cost of products sold within the fuel oil and refined fuels segment).
Cost of products sold associated with the distribution of propane and related activities of $367.0 million for
the year ended September 26, 2009 decreased $322.9 million, or 46.8%, compared to the prior year. Lower
average propane costs and lower propane volumes resulted in a decrease of $234.1 million and $71.8 million,
respectively, in cost of products sold during fiscal 2009 compared to the prior year. Cost of products sold from
wholesale and other propane activities decreased $20.1 million compared to the prior year due to lower product
costs and lower sales volumes.
33
Cost of products sold associated with the distribution of fuel oil and refined fuels of $104.6 million for the
year ended September 26, 2009 decreased $142.7 million, or 57.7%, compared to the prior year. Lower average
fuel oil and refined fuels costs and lower volumes resulted in decreases of $72.7 million and $56.2 million,
respectively, in cost of products sold during fiscal 2009 compared to the prior year. In addition, during fiscal
2008 we reported realized losses from risk management activities that were not fully offset by sales of the
physical product, resulting in a $10.8 million reduction to cost of products sold associated with our fuel oil and
refined fuels segment in fiscal 2009 compared to the prior year.
Cost of products sold in our natural gas and electricity segment of $57.2 million for the year ended
September 26, 2009 decreased $30.4 million, or 34.7%, compared to the prior year due to lower product costs
and lower sales volumes. Cost of products sold in our all other segment of $11.5 million for the year ended
September 26, 2009 decreased $3.1 million, or 21.1%, compared to the prior year primarily due to lower sales
volumes.
For the fiscal year ended September 26, 2009, total cost of products sold represented 47.3% of revenues
compared to 66.0% in the prior year. The decrease in costs as a percentage of revenues was primarily
attributable to the decline in product costs which outpaced the decline in average selling prices, and, to a much
lesser extent, the favorable variance attributable to risk management activities discussed above.
Operating Expenses
(Dollars in thousands)
Operating expenses
As a percent of total revenues
Fiscal
2009
304,767
26.7%
$
Fiscal
2008
308,071
19.6%
$
(Decrease)
$
(3,304)
Percent
(Decrease)
(1.1%)
All costs of operating our retail distribution and appliance sales and service operations are reported within
operating expenses in the consolidated statements of operations. These operating expenses include the
compensation and benefits of field and direct operating support personnel, costs of operating and maintaining our
vehicle fleet, overhead and other costs of our purchasing, training and safety departments and other direct and
indirect costs of operating our customer service centers.
Operating expenses of $304.8 million for year ended September 26, 2009 decreased $3.3 million, or 1.1%,
compared to $308.1 million in the prior year as higher variable compensation expense associated with higher
earnings was more than offset by our continued efforts to drive operational efficiencies and reduce costs across
all operating segments. Savings were primarily attributable to payroll and benefit related expenses as a result of
lower headcount, lower fuel costs to operate our fleet and lower bad debt expense.
General and Administrative Expenses
(Dollars in thousands)
General and administrative expenses
As a percent of total revenues
Fiscal
2009
Fiscal
2008
$
57,044
5.0%
$
48,134
3.1%
Increase
$
8,910
Percent
Increase
18.5%
All costs of our back office support functions, including compensation and benefits for executives and other
support functions, as well as other costs and expenses to maintain finance and accounting, treasury, legal, human
34
resources, corporate development and the information systems functions are reported within general and
administrative expenses in the consolidated statements of operations.
General and administrative expenses of $57.0 million for the year ended September 26, 2009 increased $8.9
million, or 18.5%, compared to $48.1 million during the prior year. The increase was primarily attributable to
higher variable compensation expense resulting from higher earnings in fiscal 2009 compared to the prior year,
and higher compensation costs recognized under certain long-term incentive plans.
Depreciation and Amortization
(Dollars in thousands)
Depreciation and amortization
As a percent of total revenues
Fiscal
2009
Fiscal
2008
$
30,343
2.7%
$
28,394
1.8%
Increase
$
1,949
Percent
Increase
6.9%
Depreciation and amortization expense of $30.4 million for the year ended September 26, 2009 increased
$1.9 million, or 6.9%, compared to $28.4 million in the prior year primarily as a result of accelerating
depreciation expense for certain assets retired in the second half of fiscal 2009.
Interest Expense, net
(Dollars in thousands)
Interest expense, net
As a percent of total revenues
Fiscal
2009
Fiscal
2008
$
38,267
3.3%
$
37,052
2.4%
Increase
$
1,215
Percent
Increase
3.3%
Net interest expense increased $1.2 million, or 3.3%, to $38.3 million for the year ended September 26, 2009,
compared to $37.1 million in the prior year as a result of lower market interest rates for short-term investments,
which contributed to less interest income earned, and a non-cash charge of $0.4 million to write-off the
unamortized debt issuance costs associated with the previous credit agreement which was terminated in the third
quarter of fiscal 2009.
Loss on Debt Extinguishment
On September 9, 2009, we purchased $175,000 aggregate principal amount of the 2003 Senior Notes through
a cash tender offer. In connection with the tender offer, we recognized a loss on the extinguishment of debt of
$4,624 in the fourth quarter of fiscal 2009, consisting of $2,821 for the tender premium and related fees, as well
as the write-off of $1,803 in unamortized debt origination costs and unamortized discount.
Discontinued Operations
On October 2, 2007, the Operating Partnership completed the sale of its Tirzah, South Carolina underground
granite propane storage cavern, and associated 62-mile pipeline, for approximately $53.7 million in cash, after
taking into account certain adjustments. As part of the agreement, we entered into a long-term storage
arrangement, not to exceed 7 million propane gallons, with the purchaser of the cavern that will enable us to
continue to meet the needs of our retail operations, consistent with past practices. As a result of this sale, we
reported a $43.7 million gain on disposal of discontinued operations during the first quarter of fiscal 2008.
35
Net Income and EBITDA
We reported net income of $165.2 million, or $4.99 per Common Unit, for the year ended September 26,
2009 compared to net income of $154.9 million, or $4.72 per Common Unit, in the prior year. EBITDA for
fiscal 2008 of $236.3 million increased $14.1 million, or 6.3%, compared to EBITDA of $222.2 million in the
prior year.
Net income and EBITDA for fiscal 2009 included a $4.6 million charge for the loss on extinguishment of
$175 million of our 6.875% Senior Notes. By comparison, net income and EBITDA for fiscal 2008 included a
gain (reported within discontinued operations) of $43.7 million from our sale of its Tirzah, South Carolina
underground storage cavern and associated 62-mile pipeline.
EBITDA represents net income before deducting interest expense, income taxes, depreciation and
amortization. Our management uses EBITDA as a measure of liquidity and we disclose it because we believe
that it provides our investors and industry analysts with additional information to evaluate our ability to meet our
debt service obligations and to pay our quarterly distributions to holders of our Common Units. In addition,
certain of our incentive compensation plans covering executives and other employees utilize EBITDA as the
performance target. We use this non-GAAP financial measure in order to assist industry analysts and investors
in assessing our liquidity on a year-over-year basis. Moreover, our revolving credit agreement requires us to use
EBITDA as a component in calculating our leverage and interest coverage ratios. EBITDA is not a recognized
term under GAAP and should not be considered as an alternative to net income or net cash provided by operating
activities determined in accordance with GAAP. Because EBITDA as determined by us excludes some, but not
all, items that affect net income, it may not be comparable to EBITDA or similarly titled measures used by other
companies. The following table sets forth (i) our calculations of EBITDA and (ii) a reconciliation of EBITDA, as
so calculated, to our net cash provided by operating activities:
36
(Dollars in thousands)
Net income
Add:
Provision for income taxes
Interest expense, net
Depreciation and amortization
EBITDA
Unrealized (non-cash) (gains) on changes in fair
Adjusted EBITDA
Add (subtract):
Provision for income taxes - current
Interest expense, net
Loss on debt extinguishment
Unrealized (non-cash) gains on changes in fair
Compensation cost recognized under Restricted Unit Plan
Gain on disposal of property, plant and equipment, net
Gain on disposal of discontinued operations
Changes in working capital and other assets and liabilities
Year Ended
September 26,
2009
September 27,
2008
$
165,238
$
154,880
2,486
38,267
30,343
236,334
(1,713)
234,621
(1,101)
(38,267)
4,624
1,713
2,396
(650)
-
43,215
1,903
37,052
28,394
222,229
(1,764)
220,465
(626)
(37,052)
-
1,764
2,156
(2,252)
(43,707)
(20,231)
Net cash provided by operating activities
$
246,551
$
120,517
Fiscal Year 2008 Compared to Fiscal Year 2007
Revenues
(Dollars in thousands)
Revenues
Propane
Fuel oil and refined fuels
Natural gas and electricity
All other
Total revenues
Fiscal
2008
Fiscal
2007
Increase /
(Decrease)
$
$
1,132,950
288,078
103,745
49,390
1,574,163
$
1,019,798
262,076
94,352
63,337
1,439,563
$
$
$
113,152
26,002
9,393
(13,947)
134,600
Percent
Increase /
(Decrease)
11.1%
9.9%
10.0%
(22.0%)
9.4%
Total revenues increased $134.6 million, or 9.4%, to $1,574.2 million for the year ended September 27, 2008
compared to $1,439.6 million for the year ended September 29, 2007, due to higher average selling prices
associated with higher product costs, partially offset by lower volumes. Volumes in our propane, fuel oil and
refined fuels and natural gas and electricity segments were lower in fiscal 2008 compared to the prior year
primarily due to ongoing customer conservation resulting from the historically high commodity prices, proactive
steps to manage customer credit risk, warmer weather in our service territories during the peak heating months
and, to a lesser extent, the effects of eliminating certain lower margin accounts which occurred throughout much
37
of the prior year. From a weather perspective, average heating degree days in our service territories were 94% of
normal for fiscal 2008 and flat compared to the prior year; however, the winter heating season of fiscal 2008 was
warmer than the comparable prior year period, particularly in the northeast where average heating degree days
were 7% below normal and the prior year, thus having a negative effect on volumes.
Revenues from the distribution of propane and related activities of $1,133.0 million for the year ended
September 27, 2008 increased $113.2 million, or 11.1%, compared to $1,019.8 million for the year ended
September 29, 2007, primarily due to higher average selling prices, partially offset by lower volumes. Retail
propane gallons sold in fiscal 2008 decreased 46.3 million gallons, or 10.7%, to 386.2 million gallons from 432.5
million gallons in the prior year. The average posted price of propane during fiscal 2008 increased 48.6%
compared to the average posted prices in the prior year, while our average propane selling prices during fiscal
2008 increased approximately 27.0% compared to the prior year. Additionally, revenues from wholesale and
other propane activities for the year ended September 27, 2008 decreased $13.2 million compared to the prior
year.
Revenues from the distribution of fuel oil and refined fuels of $288.1 million for the year ended September
27, 2008 increased $26.0 million, or 9.9%, from $262.1 million in the prior year, primarily due to higher average
selling prices, partially offset by lower volumes. Fuel oil and refined fuels gallons sold in fiscal 2008 decreased
28.0 million gallons, or 26.8%, to 76.5 million gallons from 104.5 million gallons in the prior year. Lower
volumes in our fuel oil and refined fuels segment were attributable to the impact of ongoing customer
conservation from continued high energy prices combined with our decision to exit certain lower margin diesel
and gasoline businesses. Our decision to exit the majority of our low sulfur diesel and gasoline businesses
resulted in a reduction in volumes in the fuel oil and refined fuels segment of approximately 9.7 million gallons,
or 34.5% of the total volume decline in fiscal 2008 compared to the prior year. The average posted price of fuel
oil during fiscal 2008 increased approximately 63.8% compared to the average posted prices in the prior year,
while our average selling prices in our fuel oil and refined fuels segment increased approximately 47.4%
compared to the prior year period.
Revenues in our natural gas and electricity segment increased $9.3 million, or 10.0%, to $103.7 million for
the year ended September 27, 2008 compared to $94.4 million in the prior year as a result of higher average
selling prices for both electricity and natural gas, partially offset by lower electricity and natural gas volumes.
Revenues in our all other segment decreased 22.0% to $49.4 million in fiscal 2008 from $63.3 million in the
prior year as a result of the decision to reduce the level of certain installation service activities. The focus of our
ongoing service offerings are in support of our existing core commodity segments.
Cost of Products Sold
(Dollars in thousands)
Cost of products sold
Propane
Fuel oil and refined fuels
Natural gas and electricity
All other
Total cost of products sold
Fiscal
2008
Fiscal
2007
Increase /
(Decrease)
$
689,921
247,310
87,600
14,605
1,039,436
$
$
$
573,305
194,213
77,116
20,784
865,418
116,616
53,097
10,484
(6,179)
174,018
$
$
Percent
Increase /
(Decrease)
20.3%
27.3%
13.6%
(29.7%)
20.1%
As a percent of total revenues
66.0%
60.1%
Cost of products sold in fiscal 2008 included a $1.8 million unrealized (non-cash) gain representing the net
38
unrealized change in the fair value of derivative instruments during the period, compared to a $7.6 million
unrealized (non-cash) loss in the prior year resulting in a decrease of $9.4 million in cost of products sold for the
year ended September 27, 2008 compared to the prior year.
Cost of products sold associated with the distribution of propane and related activities of $689.9 million
increased $116.6 million, or 20.3%, compared to the prior year. Higher average propane costs resulted in an
increase of $189.8 million in cost of products sold during fiscal 2008 compared to the prior year. The impact of
the sharp increase in commodity prices was partially offset by lower propane volumes which resulted in a $55.8
million decrease in cost of products sold during fiscal 2008 compared to the prior year. Lower wholesale and
other propane revenues, noted above, decreased cost of products sold by approximately $14.2 million compared
to the prior year. In addition, the portion of the total net change in the fair value of derivative instruments
associated with the propane segment during fiscal 2008, noted above, resulted in a $3.2 million decrease in cost
of products sold compared to the prior year.
Cost of products sold associated with our fuel oil and refined fuels segment of $247.3 million increased
$53.1 million, or 27.3%, compared to the prior year. Higher average fuel oil costs resulted in an increase of
$101.8 million in cost of products sold during fiscal 2008 compared to the prior year period. This increase was
partially offset by lower fuel oil sales volumes, which resulted in a $53.3 million decrease in cost of products
sold during fiscal 2008 compared to the prior year. In addition, as described above, risk management activities
during fiscal 2008 resulted in a $10.8 million increase in cost of products sold compared to the prior year as a
result of realized losses on futures contracts that were not fully offset by sales of physical product. The portion
of the total net change in the fair value of derivative instruments associated with the fuel oil and refined fuels
segment during the period resulted in a $6.2 million decrease in cost of products sold compared to the prior year.
Cost of products sold in our natural gas and electricity segment of $87.6 million increased $10.5 million, or
13.6%, compared to the prior year due to higher average electricity costs and, to a lesser extent, natural gas costs.
Cost of products sold in our all other segment of $14.6 million decreased $6.2 million, or 29.7%, compared to the
prior year primarily due to lower sales volumes.
For the year ended September 27, 2008, total cost of products sold represented 66.0% of revenues compared
to 60.1% in the prior year. This increase was primarily attributable to the significant increase in product costs
which we were not able to fully pass on to customers, as well as the favorable market conditions discussed above
that contributed approximately $14.7 million of incremental margin opportunities in the prior year that were not
present in fiscal 2008 and the negative effect of higher commodity prices on our risk management activities
which resulted in $10.8 million of realized losses during the second half of fiscal 2008 that were not fully offset
by sales of physical product.
Operating Expenses
(Dollars in thousands)
Operating expenses
As a percent of total revenues
Fiscal
2008
308,071
19.6%
$
Fiscal
2007
322,852
22.4%
$
Decrease
$
(14,781)
Percent
Decrease
(4.6%)
Operating expenses of $308.1 million for the year ended September 27, 2008 decreased $14.8 million, or
4.6%, compared to $322.9 million in the prior year as a result of our continued efforts to drive operational
efficiencies and reduce costs across all operating segments. Payroll and benefit related expenses declined $18.8
million due to lower headcount, as well as lower variable compensation associated with lower earnings in fiscal
2008 compared to the prior year. In addition, vehicle expenditures decreased $0.6 million compared to the prior
39
year, despite a significant increase in the cost of diesel fuel, as a result of a lower vehicle count enabled by
ongoing routing efficiencies. Savings from payroll and benefit related expenses and vehicle expenditures were
partially offset by higher bad debt expense and increased costs to operate our customer service centers in the high
energy price environment.
General and Administrative Expenses
(Dollars in thousands)
General and administrative expenses
As a percent of total revenues
Fiscal
2008
Fiscal
2007
$
48,134
3.1%
$
56,422
3.9%
Decrease
$
(8,288)
Percent
Decrease
(14.7%)
General and administrative expenses of $48.1 million for the year ended September 27, 2008 decreased $8.3
million, or 14.7%, compared to $56.4 million during the prior year. The decrease was primarily attributable to a
reduction in variable compensation resulting from lower earnings in fiscal 2008 compared to the prior year and
the reduction of compensation costs recognized under certain long-term incentive plans.
Restructuring Charges and Severance Costs
We did not record any restructuring charges for the year ended September 27, 2008. For the year ended
September 29, 2007, we recorded a charge of $1.5 million primarily related to employee termination costs
incurred as a result of further refinements to our plan to restructure our services business.
Depreciation and Amortization
(Dollars in thousands)
Depreciation and amortization
As a percent of total revenues
Fiscal
2008
Fiscal
2007
$
28,394
1.8%
$
28,790
2.0%
Decrease
$
(396)
Percent
Decrease
(1.4%)
Depreciation and amortization expense of $28.4 million for the year ended September 27, 2008 was
relatively unchanged compared to the prior year.
Interest Expense, net
(Dollars in thousands)
Interest expense, net
As a percent of total revenues
Fiscal
2008
Fiscal
2007
$
37,052
2.4%
$
35,596
2.5%
Increase
$
1,456
Percent
Increase
4.1%
Net interest expense increased $1.5 million, or 4.1%, to $37.1 million for the year ended September 27, 2008,
compared to $35.6 million in the prior year as a result of lower market interest rates for short-term investments,
which contributed to less interest income earned. As has been the case since April 2006, there were no
borrowings under our working capital facility as seasonal working capital needs have been funded through cash
40
on hand and cash flow from operations. We ended fiscal 2008 in a strong cash position with $137.7 million in
cash on the consolidated balance sheet.
Discontinued Operations
On October 2, 2007, the Operating Partnership completed the sale of its Tirzah, South Carolina underground
granite propane storage cavern, and associated 62-mile pipeline, for approximately $53.7 million in cash, after
taking into account certain adjustments. As part of the agreement, we entered into a long-term storage
arrangement, not to exceed 7 million propane gallons, with the purchaser of the cavern that will enable us to
continue to meet the needs of our retail operations, consistent with past practices. As a result of this sale, we
reported a $43.7 million gain on disposal of discontinued operations during the first quarter of fiscal 2008. The
results of operations from the Tirzah facilities have been reported within discontinued operations on the
consolidated statements of operations for fiscal 2007 and the assets and liabilities have been classified as held for
sale on the consolidated balance sheet as of September 29, 2007.
During the first quarter of fiscal 2007, in a non-cash transaction, we disposed of nine customer service
centers considered to be non-strategic in exchange for three customer service centers of another company located
in Alaska. We reported a $1.0 million gain within discontinued operations during the first quarter of fiscal 2007
for the amount by which the fair value of assets relinquished exceeded the carrying value of the assets
relinquished. During fiscal 2007 we also sold three customer service centers for net cash proceeds of $1.3
million and reported a gain on sale within discontinued operations of $0.9 million.
Net Income and EBITDA
We reported net income of $154.9 million, or $4.72 per Common Unit, for the year ended September 27,
2008 compared to net income of $127.3 million, or $3.91 per Common Unit, in the prior year. EBITDA for
fiscal 2008 of $222.2 million increased $24.4 million, or 12.3%, compared to EBITDA of $197.8 million in the
prior year.
Net income and EBITDA for fiscal 2008 included a gain (reported within discontinued operations) of $43.7
million from our sale of its Tirzah, South Carolina underground storage cavern and associated 62-mile pipeline.
By comparison, net income and EBITDA for fiscal 2007 included (i) the non-cash pension settlement charge of
$3.3 million; (ii) severance costs of $1.5 million related to positions eliminated; (iii) a gain of $2.0 million from
the recovery of a substantial portion of legal fees associated with the successful defense of a matter following the
1999 acquisition of certain propane assets in North and South Carolina; (iv) gains (reported within discontinued
operations) of $1.9 million from the sale and exchange of customer service centers considered to be non-
strategic; and (v) a non-cash adjustment to the provision for income taxes of $3.8 million.
41
The following table sets forth (i) our calculations of EBITDA and (ii) a reconciliation of EBITDA, as so
calculated, to our net cash provided by operating activities:
(Dollars in thousands)
Net income
Add:
Provision for income taxes
Interest expense, net
Depreciation and amortization - continuing operations
Depreciation and amortization - discontinued operations
EBITDA
Unrealized (non-cash) (gains) losses on changes
Adjusted EBITDA
Add (subtract):
Provision for income taxes - current
Interest expense, net
Unrealized (non-cash) gains (losses) on changes
Compensation cost recognized under Restricted Unit Plan
Gain on disposal of property, plant and equipment, net
Gain on disposal of discontinued operations
Pension settlement charge
Changes in working capital and other assets and liabilities
Year Ended
September 27,
2008
September 29,
2007
$
154,880
$
127,287
1,903
37,052
28,394
-
222,229
(1,764)
220,465
(626)
(37,052)
1,764
2,156
(2,252)
(43,707)
-
(20,231)
5,653
35,596
28,790
452
197,778
7,555
205,333
(1,853)
(35,596)
(7,555)
3,014
(2,782)
(1,887)
3,269
(15,986)
Net cash provided by operating activities
$
120,517
$
145,957
Liquidity and Capital Resources
Analysis of Cash Flows
Operating Activities. Net cash provided by operating activities for the year ended September 26, 2009
amounted to $246.6 million, an increase of $126.1 million compared to $120.5 million in the prior year. The
increase was attributable to a $63.2 million increase in earnings, after adjusting for non-cash items in both
periods (deprecation, amortization, compensation costs recognized under our Restricted Unit Plan, gains on
disposal of assets and deferred tax provision), coupled with a $62.9 million reduction in our investment in
working capital as a result of the decline in propane and fuel oil commodity prices.
Net cash provided by operating activities for the year ended September 27, 2008 amounted to $120.5 million, a
decrease of $25.5 million compared to $146.0 million in fiscal 2007. The decrease was attributable to a $21.2
million decrease in earnings, after adjusting for non-cash items in both periods (deprecation, amortization,
compensation costs recognized under our Restricted Unit Plan, gains on disposal of assets, pension settlement
charges and deferred tax provision) and a $29.3 million increased investment in working capital, partially offset
by a $25.0 million voluntary contribution to our defined benefit pension plan made in fiscal 2007. No pension
contributions were made during fiscal 2009 or fiscal 2008.
Investing Activities. Net cash used in investing activities of $16.9 million for the year ended September 26,
2009 consisted of capital expenditures of $21.8 million (including $12.2 million for maintenance expenditures
42
and $9.6 million to support the growth of operations), partially offset by the net proceeds from the sale of
property, plant and equipment of $4.9 million. Capital spending in fiscal 2009 was flat compared to fiscal 2008.
Net cash provided by investing activities of $36.6 million for the year ended September 27, 2008 consisted of
the net proceeds from the sale of discontinued operations of $53.7 million and the net proceeds from the sale of
property, plant and equipment of $4.7 million, partially offset by capital expenditures of $21.8 million (including
$12.0 million for maintenance expenditures and $9.8 million to support the growth of operations). Capital
spending in fiscal 2008 decreased $5.0 million, or 18.7%, compared to fiscal 2007 primarily as a result of lower
spending on tanks and information technology as much of the incremental spending on our field realignment
efforts has been incurred.
Financing Activities. Net cash used in financing activities for the year ended September 26, 2009 of $204.2
million reflects $106.7 million in quarterly distributions to Common Unitholders at a rate of $0.805 per Common
Unit in respect of the fourth quarter of fiscal 2008, at a rate of $0.81 per Common Unit in respect of the first
quarter of fiscal 2009, at a rate of $0.815 per Common Unit in respect of the second quarter of fiscal 2009 and at
a rate of $0.825 per Common Unit in respect of the third quarter of fiscal 2009. In addition, financing activities
for fiscal 2009 reflects $110.0 million of repayments on our term loan, which was partially funded by borrowings
of $100.0 million under the revolving credit facility executed on June 26, 2009; the $5.5 million payment of debt
issuance costs associated with the execution of the new revolving credit facility; and the repurchase of $175.0
million aggregate principal amount of our 6.875% Senior Notes for $177.8 million, which was partially funded
by the proceeds of $95.9 million from the issuance of 2,430,934 of our Common Units.
Net cash used in financing activities for the year ended September 27, 2008 of $116.0 million reflects $101.0
million in quarterly distributions to Common Unitholders at a rate of $0.75 per Common Unit in respect of the
fourth quarter of fiscal 2007, at a rate of $0.7625 per Common Unit in respect of the first quarter of fiscal 2008,
at a rate of $0.775 per Common Unit in respect of the second quarter of fiscal 2008 and at a rate of $0.80 per
Common Unit in respect of the third quarter of fiscal 2008, as well as a prepayment of $15.0 million to reduce
amounts outstanding under our previous term loan.
Equity Offering
On August 10, 2009, we sold 2,200,000 Common Units in a public offering (the “Equity Offering”) at a price
of $41.50 per Common Unit, realizing proceeds of $86.7 million, net of underwriting commissions and other
offering expenses. On August 24, 2009, we announced that the underwriters had given notice of their exercise of
their over-allotment option, in part, to acquire 230,934 Common Units at the Equity Offering price of $41.50 per
Common Unit. Net proceeds from the over-allotment exercise amounted to $9.2 million. The aggregate net
proceeds from the Equity Offering of $95.9 million were used, along with cash on hand, to fund the purchase of
$175.0 million aggregate principal amount of our 6.875% Senior Notes. These transactions increased the total
number of Common Units outstanding by 2,430,934 to 35,227,954.
Summary of Long-Term Debt Obligations and Revolving Credit Lines
As of September 26, 2009, our long-term borrowings and revolving credit lines consist of $250.0 million in
6.875% senior notes due December 2013 (the “2003 Senior Notes”) and a $250.0 million senior secured
revolving credit facility at the Operating Partnership level (the “Revolving Credit Facility”). The Revolving
Credit Facility was executed on June 26, 2009 and replaces the Operating Partnership’s previous credit facility
which, as amended, provided for a $108.0 million term loan (the “Term Loan”) and a separate $175.0 million
working capital facility both of which were scheduled to mature in March 2010. Borrowings under the
Revolving Credit Facility may be used for general corporate purposes, including working capital, capital
expenditures and acquisitions until maturity on June 25, 2013. Our Operating Partnership has the right to prepay
loans under the Revolving Credit Facility, in whole or in part, without penalty at any time prior to maturity. At
closing, the Operating Partnership borrowed $100.0 million under the Revolving Credit Facility and, with cash
43
on hand, repaid the $108.0 million then outstanding under the Term Loan and terminated the previous credit
agreement. We have standby letters of credit issued under the Revolving Credit Facility in the aggregate amount
of $57.2 million primarily in support of retention levels under our self-insurance programs, which expire
periodically through April 15, 2010. Therefore, as of September 26, 2009 we had available borrowing capacity
of $92.8 million under the Revolving Credit Facility.
On September 9, 2009, with proceeds of $95.9 million from our Equity Offering along with cash on hand, we
purchased $175.0 million of our 2003 Senior Notes through a cash tender offer. Holders who validly tendered
their 2003 Senior Notes on or prior to the early tender date of August 21, 2009 received a cash payment of
$1,012.50 for each $1,000 principal amount of 2003 Senior Notes accepted for payment, and holders who validly
tendered their 2003 Senior Notes thereafter, but on or prior to the expiration date of September 8, 2009, received
a cash payment of $982.50 for each $1,000 principal amount of 2003 Senior Notes accepted for payment.
The remaining $250 million of 2003 Senior Notes mature on December 15, 2013 and require semi-annual
interest payments. We are permitted to redeem some or all of the 2003 Senior Notes any time on or after
December 15, 2008 at redemption prices specified in the indenture governing the 2003 Senior Notes. In addition,
the 2003 Senior Notes have a change of control provision that would require us to offer to repurchase the notes at
101% of the principal amount repurchased, if the holders of the notes elected to exercise the right of repurchase.
Borrowings under the Revolving Credit Facility bear interest at prevailing interest rates based upon, at our
Operating Partnership’s option, LIBOR plus the applicable margin or the base rate, defined as the higher of the
Federal Funds Rate plus ½ of 1%, the agent bank’s prime rate, or LIBOR plus 1%, plus in each case the
applicable margin. The applicable margin is dependent upon our ratio of total debt to EBITDA on a consolidated
basis, as defined in the Revolving Credit Facility. As of September 26, 2009, the interest rate for the Revolving
Credit Facility was approximately 4.1%. The interest rate and the applicable margin will be reset at the end of
each calendar quarter.
In connection with the Revolving Credit Facility, our Operating Partnership amended its existing interest rate
swap agreement, which has a termination date of March 31, 2010, to reduce the notional amount to $100.0
million from $108.0 million. Our Operating Partnership will pay a fixed interest rate of 4.66% to the issuing
lender on the notional principal amount outstanding, effectively fixing the LIBOR portion of the interest rate at
4.66%. In return, the issuing lender will pay to our Operating Partnership a floating rate, namely LIBOR, on the
same notional principal amount. On July 31, 2009, our Operating Partnership entered into a forward starting
interest rate swap agreement with a March 31, 2010 effective date, which is commensurate with the maturity of
the existing interest rate swap agreement, and termination date of June 25, 2013. Under the forward starting
interest rate swap agreement, our Operating Partnership will pay a fixed interest rate of 3.12% to the issuing
lender on the notional principal amount outstanding, effectively fixing the LIBOR portion of the interest rate at
3.12%. In return, the issuing lender will pay to our Operating Partnership a floating rate, namely LIBOR, on the
same notional principal amount.
The Revolving Credit Facility and the 2003 Senior Notes both contain various restrictive and affirmative
covenants applicable to the Operating Partnership and the Partnership, respectively, including (i) restrictions on
the incurrence of additional indebtedness, and (ii) restrictions on certain liens, investments, guarantees, loans,
advances, payments, mergers, consolidations, distributions, sales of assets and other transactions. The Revolving
Credit Facility contains certain financial covenants (a) requiring the consolidated interest coverage ratio, as
defined, at the Partnership level to be not less than 2.5 to 1.0 as of the end of any fiscal quarter; (b) prohibiting
the total consolidated leverage ratio, as defined, at the Partnership level from being greater than 4.5 to 1.0 as of
the end of any fiscal quarter; and (c) prohibiting the senior secured consolidated leverage ratio, as defined, of the
Operating Partnership from being greater than 3.0 to 1.0 as of the end of any fiscal quarter. Under the 2003
Senior Note indenture, we are generally permitted to make cash distributions equal to available cash, as defined,
as of the end of the immediately preceding quarter, if no event of default exists or would exist upon making such
distributions, and the Partnership’s consolidated fixed charge coverage ratio, as defined, is greater than 1.75 to 1.
44
We were in compliance with all covenants and terms of the 2003 Senior Notes and the Revolving Credit Facility
as of September 26, 2009.
Partnership Distributions
We are required to make distributions in an amount equal to all of our Available Cash, as defined in the
Partnership Agreement, as amended, no more than 45 days after the end of each fiscal quarter to holders of
record on the applicable record dates. Available Cash, as defined in the Partnership Agreement, generally means
all cash on hand at the end of the respective fiscal quarter less the amount of cash reserves established by the
Board of Supervisors in its reasonable discretion for future cash requirements. These reserves are retained for the
proper conduct of our business, the payment of debt principal and interest and for distributions during the next
four quarters. The Board of Supervisors reviews the level of Available Cash on a quarterly basis based upon
information provided by management.
On October 22, 2009, we announced a quarterly distribution of $0.83 per Common Unit, or $3.32 on an
annualized basis, in respect of the fourth quarter of fiscal 2009 payable on November 10, 2009 to holders of
record on November 3, 2009. This quarterly distribution included an increase of $0.005 per Common Unit, or
$0.02 per Common Unit on an annualized basis, from the previous quarterly distribution rate representing the
twenty-third increase since our recapitalization in 1999 and a 3.1% increase in the quarterly distribution rate
since the fourth quarter of the prior year.
Pension Plan Assets and Obligations
Our defined benefit pension plan was frozen to new participants effective January 1, 2000 and, in furtherance
of our effort to minimize future increases in our benefit obligations, effective January 1, 2003, all future service
credits were eliminated. Therefore, eligible participants will receive interest credits only toward their ultimate
defined benefit under the defined benefit pension plan. There were no minimum funding requirements for the
defined benefit pension plan during fiscal 2009, 2008 or 2007. As of September 26, 2009 the plan’s projected
benefit obligation exceeded the fair value of plan assets by $17.1 million. Conversely, as of September 27, 2008
the fair value of plan assets exceeded the projected benefit obligation by $0.1 million. As a result, the funded
status of the defined benefit pension plan declined $17.2 million during fiscal 2009, which was primarily
attributable to an increase in the present value of the benefit obligation due to a general decrease in market
interest rates, partially offset by a positive return on plan assets during fiscal 2009. The funded status of pension
and other postretirement benefit plans are recognized as an asset or liability on our balance sheets and the
changes in the funded status are recognized in comprehensive income (loss) in the year the changes occur.
Our investment policies and strategies, as set forth in the Investment Management Policy and Guidelines, are
monitored by a Benefits Committee comprised of five members of management. During fiscal 2007, the Benefits
Committee proposed and the Board of Supervisors approved contributions to the plan to improve the funded status
of the projected benefit obligation and changed the plan’s asset allocation to reduce investment risk and more
closely match the expected returns on plan assets to the future cash requirements of the plan. The implementation of
this strategy resulted in a $25.0 million voluntary contribution in fiscal 2007 from cash on hand and changed the
asset allocation to reflect a greater concentration of fixed income securities.
The shift in investment strategy to a higher concentration of fixed income securities was intended to reduce
investment risk and, over the long-term, generate returns on plan assets that largely fund the annual interest on
the accumulated benefit obligation. However, as we experienced in fiscal 2009 and fiscal 2008, significant
declines in interest rates relevant to our benefit obligations, or poor performance in the broader capital markets in
which our plan assets are invested, could have an adverse impact on the funded status of the defined benefit
pension plan. For purposes of measuring the projected benefit obligation, we decreased the discount rate to
5.125% as of September 26, 2009 from 7.625% as of September 27, 2008, reflecting current market rates for debt
obligations of a similar duration to our pension obligations. The impact of the 250 basis points reduction in the
45
discount rate on the projected benefit obligation significantly exceeded the actual return on plan assets of 14.1%
in fiscal 2009, thus substantially contributing to the reduction in the funded status of the plan. For purposes of
computing net periodic pension cost for fiscal 2009, 2008 and 2007, our assumed long-term rate of return on plan
assets was 7.39%, 6.00% and 8.00%, respectively, based on the investment mix of our pension asset portfolio,
historical asset performance and expectations for future performance.
During fiscal 2007, lump sum benefit payments of $10.8 million exceeded the combined service and interest
costs of the net periodic pension cost. As a result, we recorded a non-cash settlement charge of $3.3 million in
order to accelerate recognition of a portion of cumulative unrecognized losses in the defined benefit pension
plan. These unrecognized losses were previously accumulated as a reduction to partners’ capital and were being
amortized to expense as part of our net periodic pension cost. During fiscal 2009 and fiscal 2008, the amount of
the pension benefit obligation settled through lump sum payments did not exceed the settlement threshold;
therefore, a settlement charge was not required to be recognized for fiscal 2009 or fiscal 2008. Additional
pension settlement charges may be required in future periods depending on the level of lump sum benefit
payments made in future periods.
We also provide postretirement health care and life insurance benefits for certain retired employees.
Partnership employees who were hired prior to July 1993 and retired prior to March 1998 are eligible for health care
benefits if they reached a specified retirement age while working for the Partnership. Partnership employees hired
prior to July 1993 are eligible for postretirement life insurance benefits if they reach a specified retirement age while
working for the Partnership. Effective January 1, 2000, we terminated our postretirement health care benefit plan
for all eligible employees retiring after March 1, 1998. All active and eligible employees who were to receive health
care benefits under the postretirement plan subsequent to March 1, 1998 were provided an increase to their
accumulated benefits under the defined benefit pension plan. Our postretirement health care and life insurance
benefit plans are unfunded. Effective January 1, 2006, we changed our postretirement health care plan from a self-
insured program to one that is fully insured under which we pay a portion of the insurance premium on behalf of the
eligible participants.
Long-Term Debt Obligations and Operating Lease Obligations
Contractual Obligations
The following table summarizes payments due under our known contractual obligations as of September 26,
2009.
(Dollars in thousands)
Fiscal
2010
Fiscal
2011
Fiscal
2012
Fiscal
2013
Fiscal
2014
Long-term debt obligations
Future interest payments
Operating lease obligations (a)
Self-insurance obligations (b)
Other contractual obligations
Total
-
$
25,838
14,297
12,995
24,210
77,340
$
$
-
25,058
11,461
10,239
18,278
65,036
$
$
-
25,058
8,643
7,474
17,288
58,463
$
$
100,000
25,058
6,791
5,021
14,005
150,875
$
$
250,000
8,594
5,522
3,054
14,508
281,678
$
Fiscal
2015 and
thereafter
-
$
-
4,223
13,465
64,115
81,803
$
(a) Payments exclude costs associated with insurance, taxes and maintenance, which are not material to the
operating lease obligations.
(b) The timing of when payments are due for our self-insurance obligations is based on estimates that may
differ from when actual payments are made. In addition, the payments do not reflect amounts to be
46
recovered from our insurance providers, which was $14.8 million as of September 26, 2009 and included
in other assets on the consolidated balance sheet.
Additionally, we have standby letters of credit in the aggregate amount of $57.2 million, in support of
retention levels under our casualty insurance programs and certain lease obligations, which expire periodically
through April 15, 2010.
Operating Leases
We lease certain property, plant and equipment for various periods under noncancelable operating leases,
including approximately 55% of our vehicle fleet, approximately 25% of our customer service centers and
portions of our information systems equipment. Rental expense under operating leases was $17.3 million, $17.7
million and $19.6 million for fiscal 2009, 2008 and 2007, respectively. Future minimum rental commitments under
noncancelable operating lease agreements as of September 26, 2009 are presented in the table above.
Off-Balance Sheet Arrangements
Guarantees
Certain of our operating leases, primarily those for transportation equipment with remaining lease periods
scheduled to expire periodically through fiscal 2016, contain residual value guarantee provisions. Under those
provisions, we guarantee that the fair value of the equipment will equal or exceed the guaranteed amount upon
completion of the lease period, or we will pay the lessor the difference between fair value and the guaranteed
amount. Although the fair value of equipment at the end of its lease term has historically exceeded the
guaranteed amounts, the maximum potential amount of aggregate future payments we could be required to make
under these leasing arrangements, assuming the equipment is deemed worthless at the end of the lease term, is
approximately $18.3 million. The fair value of residual value guarantees for outstanding operating leases was de
minimis as of September 26, 2009 and September 27, 2008.
Recently Issued Accounting Standards
In December 2008, the Financial Accounting Standards Board (“FASB”) issued new financial reporting
guidance to require more detailed disclosures about employers' pension plan assets. These new disclosures will
include more information on investment strategies, major categories of plan assets, concentrations of risk within
plan assets and valuation techniques used to measure the fair value of plan assets. The new guidance is effective
for fiscal years ending after December 15, 2009, which will be our 2010 fiscal year ending September 25, 2010.
Since it only addresses disclosures, the adoption of the new guidance is not expected to have an impact on our
consolidated financial position, results of operations and cash flows.
In December 2007, the FASB issued revised accounting guidance concerning business combinations. Among
other things, this revised guidance requires an entity to recognize acquired assets, liabilities assumed and any
noncontrolling interest at their respective fair values as of the acquisition date, clarifies how goodwill involved in
a business combination is to be recognized and measured, as well as requires the expensing of acquisition-related
costs as incurred. Most of its provisions are effective for business combinations entered into in fiscal years
beginning on or after December 15, 2008, which will be our 2010 fiscal year beginning September 27, 2009, with
early adoption prohibited. Certain provisions, in particular a provision related to the accounting for acquired tax
benefits, are required to be applied in future fiscal years regardless of when the business combination occurred.
To the extent our Corporate Entities generate taxable profits in future years that enable the utilization of tax
benefits acquired in the Agway Energy acquisition, the corresponding reduction in the valuation allowance will
be recorded as a reduction in the provision for income taxes.
47
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Commodity Price Risk
We enter into product supply contracts that are generally one-year agreements subject to annual renewal, and
also purchase product on the open market. Our propane supply contracts typically provide for pricing based
upon index formulas using the posted prices established at major supply points such as Mont Belvieu, Texas, or
Conway, Kansas (plus transportation costs) at the time of delivery. In addition, to supplement our annual
purchase requirements, we may utilize forward fixed price purchase contracts to acquire a portion of the propane
that we resell to our customers, which allows us to manage our exposure to unfavorable changes in commodity
prices and to ensure adequate physical supply. The percentage of contract purchases, and the amount of supply
contracted for under forward contracts at fixed prices, will vary from year to year based on market conditions. In
certain instances, and when market conditions are favorable, we are able to purchase product under our supply
arrangements at a discount to the market.
Product cost changes can occur rapidly over a short period of time and can impact profitability. We attempt
to reduce commodity price risk by pricing product on a short-term basis. The level of priced, physical product
maintained in storage facilities and at our customer service centers for immediate sale to our customers will vary
depending on several factors, including, but not limited to, price, availability of supply, and demand for a given
time of the year. Typically, our on hand priced position does not exceed more than four to eight weeks of our
supply needs, depending on the time of the year. In the course of normal operations, we routinely enter into
contracts such as forward priced physical contracts for the purchase or sale of propane and fuel oil that, under
accounting rules for derivative instruments and hedging activities, qualify for and are designated as normal
purchase or normal sale contracts. Such contracts are exempted from fair value accounting and are accounted for
at the time product is purchased or sold under the related contract.
Under our hedging and risk management strategies, we enter into a combination of exchange-traded futures
and option contracts, forward contracts and, in certain instances, over-the-counter option contracts (collectively,
“derivative instruments”) to manage the price risk associated with priced, physical product and with future
purchases of the commodities used in our operations, principally propane and fuel oil, as well as to ensure the
availability of product during periods of high demand. We do not use derivative instruments for speculative or
trading purposes. Futures and forward contracts require that we sell or acquire propane or fuel oil at a fixed price
for delivery at fixed future dates. An option contract allows, but does not require, its holder to buy or sell
propane or fuel oil at a specified price during a specified time period. However, the writer of an option contract
must fulfill the obligation of the option contract, should the holder choose to exercise the option. At expiration,
the contracts are settled by the delivery of the product to the respective party or are settled by the payment of a
net amount equal to the difference between the then current price and the fixed contract price or option exercise
price. To the extent that we utilize derivative instruments to manage exposure to commodity price risk and
commodity prices move adversely in relation to the contracts, we could suffer losses on those derivative
instruments when settled. Conversely, if prices move favorably, we could realize gains. Under our hedging and
risk management strategy, realized gains or losses on derivative instruments will typically offset losses or gains
on the physical inventory once the product is sold to customers at market prices.
Market Risk
We are subject to commodity price risk to the extent that propane or fuel oil market prices deviate from fixed
contract settlement amounts. Futures traded with brokers of the NYMEX require daily cash settlements in
margin accounts. Forward and option contracts are generally settled at the expiration of the contract term either
by physical delivery or through a net settlement mechanism. Market risks associated with futures, options and
forward contracts are monitored daily for compliance with our Hedging and Risk Management Policy which
includes volume limits for open positions. Open inventory positions are reviewed and managed daily as to
exposures to changing market prices.
48
Credit Risk
Futures and fuel oil options are guaranteed by the NYMEX and, as a result, have minimal credit risk. We are
subject to credit risk with over-the-counter forward and propane option contracts to the extent the counterparties
do not perform. We evaluate the financial condition of each counterparty with which we conduct business and
establish credit limits to reduce exposure to the risk of non-performance by our counterparties.
Interest Rate Risk
A portion of our borrowings bear interest at prevailing interest rates based upon, at the Operating
Partnership’s option, LIBOR, plus an applicable margin or the base rate, defined as the higher of the Federal
Funds Rate plus ½ of 1% or the agent bank’s prime rate, or LIBOR plus 1%, plus the applicable margin. The
applicable margin is dependent on the level of the Partnership’s total leverage (the total of debt to EBITDA).
Therefore, we are subject to interest rate risk on the variable component of the interest rate. We manage our
interest rate risk by entering into interest rate swap agreements. The interest rate swaps have been designated as
a cash flow hedge. Changes in the fair value of the interest rate swaps are recognized in other comprehensive
income (“OCI”) until the hedged item is recognized in earnings. At September 26, 2009, the fair value of the
interest rate swaps was $4.2 million representing an unrealized loss and is included within other current liabilities
and other liabilities, as applicable, with a corresponding debit in OCI.
Derivative Instruments and Hedging Activities
All of our derivative instruments are reported on the balance sheet at their fair values. On the date that
futures, forward and option contracts are entered into, we make a determination as to whether the derivative
instrument qualifies for designation as a hedge. Changes in the fair value of derivative instruments are recorded
each period in current period earnings or OCI, depending on whether a derivative instrument is designated as a
hedge and, if so, the type of hedge. For derivative instruments designated as cash flow hedges, we formally
assess, both at the hedge contract’s inception and on an ongoing basis, whether the hedge contract is highly
effective in offsetting changes in cash flows of hedged items. Changes in the fair value of derivative instruments
designated as cash flow hedges are reported in OCI to the extent effective and reclassified into cost of products
sold during the same period in which the hedged item affects earnings. The mark-to-market gains or losses on
ineffective portions of cash flow hedges are immediately recognized in cost of products sold. Changes in the fair
value of derivative instruments that are not designated as cash flow hedges, and that do not meet the normal
purchase and normal sale exemption, are recorded within cost of products sold as they occur. Cash flows
associated with derivative instruments are reported as operating activities within the consolidated statement of
cash flows.
At September 26, 2009, the fair value of derivative instruments described above resulted in current
derivative assets (unrealized gains) of $9.2 million included within other current assets, non-current derivative
assets of $0.5 million included within other assets, $4.8 million of derivative liabilities (unrealized losses)
included within other current liabilities and non-current derivative liabilities of $0.2 million included within
other liabilities. Cost of products sold included unrealized (non-cash) gains of $1.7 million and $1.8 million for
the years ended September 26, 2009 and September 27, 2008, respectively, attributable to the change in fair
value of derivative instruments not designated as cash flow hedges. Our outstanding commodity-related
derivatives mature between fiscal 2010 and fiscal 2011, and have a weighted average maturity of approximately
7 months as of September 26, 2009.
49
Sensitivity Analysis
In an effort to estimate our exposure to unfavorable market price changes in commodities related to our open
positions under derivative instruments, we developed a model that incorporates the following data and
assumptions:
A. The fair value of open positions as of September 26, 2009 for each of the future periods.
B. The estimated forward market prices as of September 26, 2009 as derived from the NYMEX for
traded commodities for each of the future periods.
C. The market prices determined in B. above were adjusted adversely by a hypothetical 10% change in
the forward prices and compared to the fair value amounts in A. above to project the potential
negative impact on earnings that would be recognized for the respective scenario.
Based on the sensitivity analysis described above, the hypothetical 10% adverse change in market prices for
each of the future months for which a future or option contract exists indicates a reduction in potential future net
gains of $2.5 million as of September 26, 2009. The above hypothetical change does not reflect the worst case
scenario. Actual results may be significantly different depending on market conditions and the composition of the
open position portfolio.
50
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Our Consolidated Financial Statements and the Report of Independent Registered Public Accounting Firm
thereon listed on the accompanying Index to Financial Statements (see page F-1) and the Supplemental Financial
Information listed on the accompanying Index to Financial Statement Schedule (see page S-1) are included herein.
Selected Quarterly Financial Data
Fiscal 2009
Revenues
Cost of products sold
Income (loss) before interest expense, loss on debt
extinguishment and provision for income taxes (a)
Loss on debt extinguishment (b)
Net income (loss) (a)
Net income (loss) per common unit - basic (d)
Net income (loss) per common unit - diluted (d)
Cash provided by (used in)
Operating activities
Investing activities
Financing activities
EBITDA (e)
Adjusted EBITDA (e)
Retail gallons sold
Propane
Fuel oil and refined fuels
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
Total
Year
$
363,315
174,230
$
445,225
208,259
$
184,372
87,463
$
150,242
70,433
$
1,143,154
540,385
90,229
-
80,688
2.46
2.45
125,194
-
114,866
3.50
3.48
3,793
-
(7,435)
(0.23)
(0.23)
(8,601)
(4,624)
(22,881)
(0.67)
(0.67)
210,615
(4,624)
165,238
4.99
4.96
25,004
(3,724)
(28,390)
97,252
82,246
$
$
133,948
(2,515)
(26,564)
132,325
142,015
$
$
64,546
(3,632)
(40,272)
11,506
17,654
$
$
23,053
(6,981)
(108,998)
$
(4,749)
$
(7,294)
246,551
(16,852)
(204,224)
236,334
234,621
$
$
99,047
16,716
134,512
24,125
61,212
9,677
49,123
6,863
343,894
57,381
Fiscal 2008
Revenues
Cost of products sold
Income (loss) before interest expense and provision for
income taxes (a)
Income (loss) from continuing operations (a)
Discontinued operations:
Gain on disposal of discontinued operations (c)
Net income (loss) (a)
Net income (loss) from continuing operations per
common unit - basic (d)
Net income (loss) per common unit - basic (d)
Net income (loss) per common unit - diluted (d)
$
425,109
277,715
$
587,097
380,757
$
305,476
212,974
$
256,481
167,990
1,574,163
$
1,039,436
51,789
41,722
43,707
85,429
1.27
2.61
2.60
104,375
94,523
(4,380)
(13,747)
(1,656)
(11,325)
-
94,523
-
(13,747)
-
(11,325)
2.89
2.89
2.87
(0.42)
(0.42)
(0.42)
(0.35)
(0.35)
(0.35)
150,128
111,173
43,707
154,880
3.39
4.72
4.70
Cash (used in) provided by
Operating activities
Investing activities
Financing activities
EBITDA (e)
Adjusted EBITDA (e)
Retail gallons sold
Propane
Fuel oil and refined fuels
(41,953)
48,875
(24,539)
102,555
105,238
$
$
50,340
(3,553)
(24,953)
111,482
113,817
$
$
48,601
(5,419)
(25,362)
2,779
(1,916)
$
$
63,529
(3,273)
(41,181)
5,413
3,326
$
$
120,517
36,630
(116,035)
222,229
220,465
$
$
111,937
23,594
146,252
31,435
71,420
12,614
56,613
8,872
386,222
76,515
51
Due to the seasonality of the retail propane business, our first and second quarter revenues and earnings are
consistently greater than third and fourth quarter results. The following presents our selected quarterly financial
data for the last two fiscal years (unaudited; in thousands, except per unit amounts).
(a) These amounts include gains from the disposal of property, plant and equipment of $0.7 million for fiscal
2009 and $2.3 million for fiscal 2008.
(b) During the fourth quarter of fiscal 2009, we purchased $175.0 million aggregate principal amount of the
2003 Senior Notes through a cash tender offer. In connection with the tender offer, we recognized a loss on
the extinguishment of debt of $4.6 million in the fourth quarter of fiscal 2009, consisting of $2.8 million for
the tender premium and related fees, as well as the write-off of $1.8 million in unamortized debt origination
costs and unamortized discount.
(c) Gain on disposal of discontinued operations reflects a $43.7 million gain on the Tirzah Sale during the first
quarter of fiscal 2008 for net cash proceeds of $53.7 million. These gains were accounted for within
discontinued operations.
(d) Basic net income (loss) per Common Unit is computed under by dividing net income (loss) by the weighted
average number of outstanding Common Units, and restricted units granted under the Restricted Unit Plans
to retirement-eligible grantees. Diluted net income per Common Unit is computed by dividing net income
(loss) by the weighted average number of outstanding Common Units and unvested restricted units granted
under our Restricted Unit Plans.
(e) EBITDA represents net income before deducting interest expense, income taxes, depreciation and
amortization. Adjusted EBITDA represents EBITDA excluding the unrealized net gain or loss on mark-to-
market activity for derivative instruments. Our management uses EBITDA and Adjusted EBITDA as
measures of liquidity and we are including them because we believe that they provide our investors and
industry analysts with additional information to evaluate our ability to meet our debt service obligations and
to pay our quarterly distributions to holders of our Common Units. In addition, certain of our incentive
compensation plans covering executives and other employees utilize Adjusted EBITDA as the performance
target. Moreover, our revolving credit agreement requires us to use Adjusted EBITDA as a component in
calculating our leverage and interest coverage ratios. EBITDA and Adjusted EBITDA are not recognized
terms under GAAP and should not be considered as an alternative to net income or net cash provided by
operating activities determined in accordance with GAAP. Because EBITDA and Adjusted EBITDA as
determined by us excludes some, but not all, items that affect net income, they may not be comparable to
EBITDA and Adjusted EBITDA or similarly titled measures used by other companies. The following table
sets forth (i) our calculations of EBITDA and (ii) a reconciliation of EBITDA, as so calculated, to our net
cash provided by operating activities (amounts in thousands):
52
Fiscal 2009
Net income (loss)
Add:
Provision for income taxes
Interest expense, net
Depreciation and amortization
EBITDA
Unrealized (non-cash) (gains) losses on changes in fair
value of derivatives
Adjusted EBITDA
Add (subtract):
Provision for income taxes - current
Interest expense, net
Loss on debt extinguishment
Unrealized (non-cash) gains (losses) on changes in
fair value of derivatives
Compensation cost recognized under
Restricted Unit Plan
(Gain) loss on disposal of property,
plant and equipment, net
Changes in working capital and other
assets and liabilities
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
Total
Year
$
80,688
$
114,866
$
(7,435)
$
(22,881)
$
165,238
138
9,403
7,023
97,252
(15,006)
82,246
(138)
(9,403)
-
886
9,442
7,131
132,325
9,690
142,015
1,160
10,068
7,713
11,506
6,148
17,654
(426)
(9,442)
-
(240)
(10,068)
-
302
9,354
8,476
(4,749)
(2,545)
(7,294)
(297)
(9,354)
4,624
15,006
(9,690)
(6,148)
2,545
569
672
644
(230)
(393)
(147)
511
120
2,486
38,267
30,343
236,334
(1,713)
234,621
(1,101)
(38,267)
4,624
1,713
2,396
(650)
(63,046)
11,212
62,851
32,198
43,215
Net cash provided by operating activities
$
25,004
$
133,948
$
64,546
$
23,053
$
246,551
Fiscal 2008
Net income (loss)
Add:
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
Total
Year
$
85,429
$
94,523
$
(13,747)
$
(11,325)
$
154,880
Provision for (benefit from) income taxes
Interest expense, net
Depreciation and amortization
EBITDA
Unrealized (non-cash) losses (gains) on changes in fair
value of derivatives
Adjusted EBITDA
Add (subtract):
(Provision for) benefit from income taxes - current
Interest expense, net
Unrealized (non-cash) (gains) losses on changes in
fair value of derivatives
Compensation cost recognized under
Restricted Unit Plan
Gain on disposal of property,
plant and equipment, net
Gain on disposal of discontinued operations
Changes in working capital and other
assets and liabilities
1,679
8,388
7,059
102,555
2,683
105,238
434
9,418
7,107
111,482
2,335
113,817
(402)
(8,388)
(190)
(9,418)
(157)
9,524
7,159
2,779
(4,695)
(1,916)
(87)
(9,524)
(53)
9,722
7,069
5,413
(2,087)
3,326
53
(9,722)
(2,683)
(2,335)
4,695
2,087
(67)
(1,429)
(43,707)
753
(283)
-
817
(109)
-
653
(431)
-
1,903
37,052
28,394
222,229
(1,764)
220,465
(626)
(37,052)
1,764
2,156
(2,252)
(43,707)
(90,515)
(52,004)
54,725
67,563
(20,231)
Net cash (used in) provided by operating activities
$
(41,953)
$
50,340
$
48,601
$
63,529
$
120,517
53
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
DISCLOSURE CONTROLS AND PROCEDURES. The Partnership maintains disclosure controls and
procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (the “Exchange
Act”)) that are designed to provide reasonable assurance that information required to be disclosed in the
Partnership’s filings under the Exchange Act is recorded, processed, summarized and reported within the periods
specified in the rules and forms of the SEC and that such information is accumulated and communicated to the
Partnership’s management, including its principal executive officer and principal financial officer, as
appropriate, to allow timely decisions regarding required disclosure.
Before filing this Annual Report, the Partnership completed an evaluation under the supervision and with the
participation of the Partnership’s management, including the Partnership’s principal executive officer and
principal financial officer, of the effectiveness of the design and operation of the Partnership’s disclosure
controls and procedures as of September 26, 2009. Based on this evaluation, the Partnership’s principal
executive officer and principal financial officer concluded that the Partnership’s disclosure controls and
procedures were effective at the reasonable assurance level as of September 26, 2009.
CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING. There have not been any
changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) of the
Exchange Act) during the quarter ended September 26, 2009, that have materially affected, or are reasonably
likely to materially affect, our internal control over financial reporting. Management’s Report on Internal
Control over Financial Reporting is included below.
In the ordinary course of business, we review our system of internal control over financial reporting and
make changes to our systems and processes to improve controls and increase efficiency, while ensuring that we
maintain an effective internal control environment. Changes may include such activities as implementing new,
more efficient systems and automating manual processes.
MANAGEMENT'S REPORT ON
Management of the Partnership is responsible for establishing and maintaining adequate internal control over
financial reporting. The Partnership's internal control over financial reporting is designed to provide reasonable
assurance as to the reliability of the Partnership's financial reporting and the preparation of financial statements
for external purposes in accordance with generally accepted accounting principles.
INTERNAL CONTROL OVER FINANCIAL REPORTING.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect
misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the degree of compliance with the
policies or procedures may deteriorate.
The Partnership’s management has assessed the effectiveness of the Partnership’s internal control over
financial reporting as of September 26, 2009. In making this assessment, the Partnership used the criteria
established by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in “Internal
Control-Integrated Framework.” These criteria are in the areas of control environment, risk assessment, control
activities, information and communication, and monitoring. The Partnership's assessment included documenting,
evaluating and testing the design and operating effectiveness of its internal control over financial reporting.
54
Based on the Partnership’s assessment, as described above, management has concluded that, as of September
26, 2009, the Partnership’s internal control over financial reporting was effective.
Our independent registered public accounting firm, PricewaterhouseCoopers LLP, issued an attestation
report dated November 25, 2009 on the effectiveness of our internal control over financial reporting, which is
included herein.
ITEM 9B. OTHER INFORMATION
None.
55
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Partnership Management
Our Partnership Agreement provides that all management powers over our business and affairs are exclusively
vested in our Board of Supervisors and, subject to the direction of the Board of Supervisors, our officers. No
Unitholder has any management power over our business and affairs or actual or apparent authority to enter into
contracts on behalf of or otherwise to bind us. There are currently six Supervisors, who serve on the Board of
Supervisors pursuant to the terms of the Partnership Agreement. Under the current Partnership Agreement, all
Supervisors are elected by the Common Unitholders for three-year terms. Most recently, all six current Supervisors
were elected to three-year terms at the Tri-Annual Meeting held on July 22, 2009 (see Item 4 above).
Five Supervisors, who are not officers or employees of the Partnership or its subsidiaries, serve on the Audit
Committee with authority to review, at the request of the Board of Supervisors specific matters as to which the
Board of Supervisors believes there may be a conflict of interest, or which may be required to be disclosed pursuant
to Item 404(a) of Regulation S-K adopted by the Securities and Exchange Commission, in order to determine if the
resolution or course of action in respect of such conflict proposed by the Board of Supervisors is fair and reasonable
to us. Under the Partnership Agreement, any matter that receives the “Special Approval” of the Audit Committee
(i.e., approval by a majority of the members of the Audit Committee) is conclusively deemed to be fair and
reasonable to us, is deemed approved by all of our partners and shall not constitute a breach of the Partnership
Agreement or any duty stated or implied by law or equity as long as the material facts known to the party having the
potential conflict of interest regarding that matter were disclosed to the Audit Committee at the time it gave Special
Approval. The Audit Committee also assists the Board of Supervisors in fulfilling its oversight responsibilities
relating to (a) integrity of the Partnership’s financial statements and internal control over financial reporting; (b)
the Partnership’s compliance with applicable laws, regulations and its code of conduct; (c) independence and
qualifications of the independent registered public accounting firm; (d) performance of the internal audit function
and the independent registered public accounting firm; and (e) accounting complaints.
The Board of Supervisors has determined that all five members of the Audit Committee, Harold R. Logan,
Jr., John Hoyt Stookey, Dudley C. Mecum, John D. Collins and Jane Swift are audit committee financial experts
and are independent within the meaning of the NYSE corporate governance listing standards and in accordance
with Rule 10A-3 of the Exchange Act, Item 407 of Regulation S-K and the Partnership’s criteria for Supervisor
independence (as discussed in Item 13, herein) as of the date of this Annual Report. Mr. Logan, Chairman of the
Board, presides at the regularly scheduled executive sessions of the non-management Supervisors, all of whom
are independent, held as part of the meetings of the Audit Committee. Investors and other parties interested in
communicating directly with the non-management Supervisors as a group may do so by writing to the Non-
Management Members of the Board of Supervisors, c/o Company Secretary, Suburban Propane Partners, L.P.,
P.O. Box 206, Whippany, New Jersey 07981-0206.
56
Board of Supervisors and Executive Officers of the Partnership
The following table sets forth certain information with respect to the members of the Board of Supervisors and
our executive officers as of November 23, 2009. Officers are appointed by the Board of Supervisors for one-year
terms and Supervisors are elected by the Unitholders for three-year terms.
Name
Age
Michael J. Dunn, Jr. ………………. 60
Michael A. Stivala………………… 40
Michael M. Keating……………….. 56
45
A. Davin D’Ambrosio……………..
56
Paul Abel………………………….
52
Mark Anton, II…………………….
45
Steven C. Boyd……………………
48
Douglas T. Brinkworth……………
44
Neil Scanlon……………………….
Mark Wienberg……………………
47
39
Michael Kuglin……………………
Harold R. Logan, Jr. ……………… 65
79
John Hoyt Stookey….……………..
Dudley C. Mecum…………………
John D. Collins……………………
74
71
Jane Swift…………………………
44
Position With the Partnership
President and Chief Executive Officer; Member of the
Board of Supervisors
Chief Financial Officer
Senior Vice President - Administration
Vice President and Treasurer
Vice President, General Counsel and Secretary
Vice President – Business Development
Vice President – Field Operations
Vice President – Product Supply
Vice President – Information Services
Vice President – Operational Support and Analysis
Controller and Chief Accounting Officer
Member of the Board of Supervisors (Chairman)
Member of the Board of Supervisors (Chairman of the
Compensation Committee)
Member of the Board of Supervisors
Member of the Board of Supervisors (Chairman of the
Audit Committee)
Member of the Board of Supervisors
In accordance with a management succession plan developed by the Compensation Committee of the
Partnership’s Board of Supervisors and Mark Alexander, our Chief Executive Officer, Mr. Alexander stepped
down from his position as Chief Executive Officer of the Partnership at the conclusion of fiscal 2009. At that
time, Michael J. Dunn, Jr., our President, assumed the additional role of Chief Executive Officer effective
September 27, 2009 (the beginning of our fiscal 2010).
Mr. Dunn has served as President since May 2005 and as Chief Executive Officer since September 2009. From
June 1998 until May 2005 he was Senior Vice President, becoming Senior Vice President – Corporate Development
in November 2002. Mr. Dunn has served as a Supervisor since July 1998. He was Vice President – Procurement
and Logistics from March 1997 until June 1998. Before joining the Partnership, Mr. Dunn was Vice President of
Commodity Trading for the investment banking firm of Goldman Sachs & Company (“Goldman Sachs”). Mr. Dunn
is the sole member of the General Partner.
Mr. Stivala has served as Chief Financial Officer since November 2009, and Chief Financial Officer and
Chief Accounting Officer since October 2007. Prior to that he was Controller and Chief Accounting Officer
since May 2005 and Controller since December 2001. Before joining the Partnership, he held several positions
with PricewaterhouseCoopers LLP, an international accounting firm, most recently as Senior Manager in the
Assurance practice. Mr. Stivala is a Certified Public Accountant and a member of the American Institute of
Certified Public Accountants.
Mr. Keating has served as Senior Vice President – Administration since July 2009. From July 1996 to that date
he was Vice President – Human Resources and Administration. He previously held senior human resource positions
at Hanson Industries (the United States management division of Hanson plc, a global diversified industrial
conglomerate) and Quantum Chemical Corporation (“Quantum”), a predecessor of the Partnership.
57
Mr. D’Ambrosio has served as Treasurer since November 2002 and was additionally made a Vice President
in October 2007. He served as Assistant Treasurer from October 2000 to November 2002 and as Director of
Treasury Services from January 1998 to October 2000. Mr. D’Ambrosio joined the Partnership in May 1996
after ten years in the commercial banking industry.
Mr. Abel has served as General Counsel and Secretary since June 2006 and was additionally made a Vice
President in October 2007. From May 2005 until June 2006, Mr. Abel was Assistant General Counsel of
Velocita Wireless, L.P., the owner and operator of a nationwide wireless data network. From 1998 until May
2005, Mr. Abel was Vice President, Secretary and General Counsel of AXS-One Inc. (formerly known as
Computron Software, Inc.), an international business software company.
Mr. Anton has served as Vice President – Business Development since he joined the Partnership in 1999.
Prior to joining the Partnership, Mr. Anton worked as an Area Manager for another large multi-state propane
marketer and was a Vice President at several large investment banking organizations.
Mr. Boyd has served as Vice President – Field Operations (formerly Vice President – Operations) since
October 2008. Prior to that he was Southeast and Western Area Vice President since March 2007, Managing
Director – Area Operations since November 2003 and Regional Manager – Northern California since May 1997.
Mr. Boyd held various managerial positions with predecessors of the Partnership from 1986 through 1996.
Mr. Brinkworth has served as Vice President – Product Supply (formerly Vice President – Supply) since
May 2005. Mr. Brinkworth joined the Partnership in April 1997 after a nine year career with Goldman Sachs
and, since joining the Partnership, has served in various positions in the product supply area.
Mr. Scanlon became Vice President – Information Services in November 2008. Prior to that he served as
Assistant Vice President – Information Services since November 2007, Managing Director – Information
Services from November 2002 to November 2007 and Director – Information Services from April 1997 until
November 2002. Prior to joining the Partnership, Mr. Scanlon spent several years with JP Morgan & Co., most
recently as Vice President – Corporate Systems and earlier held several positions with Andersen Consulting
(“Accenture”), an international systems consulting firm, most recently as Manager.
Mr. Wienberg has served as Vice President – Operational Support and Analysis (formerly Vice President –
Operational Planning) since October 2007. Prior to that he served as Managing Director, Financial Planning and
Analysis from October 2003 to October 2007 and as Director, Financial Planning and Analysis from July 2001 to
October 2003. Prior to joining the Partnership, Mr. Wienberg was Assistant Vice President – Finance of
International Home Foods Corp., a consumer products manufacturer.
Mr. Kuglin has served as Controller and Chief Accounting Officer since November 2009, and Controller
since October 2007. For the eight years prior to joining the Partnership he held several financial and managerial
positions with Alcatel-Lucent, a global communications solutions provider. Prior to Alcatel-Lucent, Mr. Kuglin
held several positions with the international accounting firm PricewaterhouseCoopers LLP, most recently
Manager in the Assurance practice. Mr. Kuglin is a Certified Public Accountant and a member of the American
Institute of Certified Public Accountants.
Mr. Logan has served as a Supervisor since March 1996 and was elected as Chairman of the Board of
Supervisors in January 2007. Mr. Logan is a Co-Founder and, from 2006 to the present has been serving as a
Director of Basic Materials and Services LLC, an investment company that has invested in companies that
provide specialized infrastructure services and materials for the pipeline construction industry and the sand/silica
industry. From 2003 to September 2006, Mr. Logan was a Director and Chairman of the Finance Committee of
the Board of Directors of TransMontaigne Inc., which provided logistical services (i.e. pipeline, terminaling and
marketing) to producers and end-users of refined petroleum products. From 1995 to 2002, Mr. Logan was
Executive Vice President/Finance, Treasurer and a Director of TransMontaigne Inc. From 1987 to 1995, Mr.
58
Logan served as Senior Vice President of Finance and a Director of Associated Natural Gas Corporation, an
independent gatherer and marketer of natural gas, natural gas liquids and crude oil. Mr. Logan is also a Director
of Graphic Packaging Holding Company, Hart Energy Publishing LLP and Cimarex Energy Co.
Mr. Stookey has served as a Supervisor since March 1996. He was Chairman of the Board of Supervisors
from March 1996 through January 2007. From 1986 until September 1993, he was the Chairman, President and
Chief Executive Officer of Quantum. He served as non-executive Chairman and a Director of Quantum from its
acquisition by Hanson plc in September 1993 until October 1995, at which time he retired. Since then, Mr.
Stookey has served as a trustee for a number of non-profit organizations, including founding and serving as non-
executive Chairman of Per Scholas Inc. (a non-profit organization dedicated to using technology to improve the
lives of residents of the South Bronx) and Landmark Volunteers (places high school students in volunteer
positions with non-profit organizations during summer vacations) and has also served on the Board of Directors
of The Clark Foundation, The Robert Sterling Clark Foundation and The Berkshire Taconic Community
Foundation.
Mr. Mecum has served as a Supervisor since June 1996. He has been a Managing Director of Capricorn
Holdings, LLC (a sponsor of and investor in leveraged buyouts) since June 1997. Mr. Mecum was a partner of G.L.
Ohrstrom & Co. (a sponsor of and investor in leveraged buyouts) from 1989 to June 1996.
Mr. Collins has served as a Supervisor since April 2007. He served with KPMG, LLP, an international
accounting firm, from 1962 until 2000, most recently as senior audit partner of its New York office. He has
served as a United States representative on the International Auditing Procedures Committee, a committee of
international accountants responsible for establishing international auditing standards. Mr. Collins is a Director
of Montpelier Re, Mrs. Fields Original Cookies, Inc. and Columbia Atlantic Funds, and serves as a Trustee of
LeMoyne College.
Ms. Swift has served as a Supervisor since April 2007. She is the founder of WNP Consulting, LLC,
providing expert advice and guidance to early stage education companies. From 2003 to 2006 she was a General
Partner at Arcadia Partners, a venture capital firm focused on the education industry. She currently serves on the
boards of K12, Inc., Animated Speech Company and Sally Ride Science Inc. and several not-for-profit boards,
including The Republican Majority for Choice and Landmark Volunteers, Inc. Prior to joining Arcadia, Ms.
Swift served for 15 years in Massachusetts state government, becoming Massachusetts’ first woman governor in
2001.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act requires our Supervisors, executive officers and holders of ten percent or
more of our Common Units to file initial reports of ownership and reports of changes in ownership of our
Common Units with the SEC. Supervisors, executive officers and ten percent Unitholders are required to furnish
the Partnership with copies of all Section 16(a) forms that they file. Based on a review of these filings, we
believe that all such filings were timely made during fiscal 2009.
Codes of Ethics and of Business Conduct
We have adopted a Code of Ethics that applies to our principal executive officer, principal financial officer
and principal accounting officer, and a Code of Business Conduct that applies to all of our employees, officers
and Supervisors. A copy of our Code of Ethics and our Code of Business Conduct is available without charge
from our website at www.suburbanpropane.com or upon written request directed to: Suburban Propane Partners,
L.P., Investor Relations, P.O. Box 206, Whippany, New Jersey 07981-0206. Any amendments to, or waivers
from, provisions of our Code of Ethics or our Code of Business Conduct that apply to our principal executive
officer, principal financial officer and principal accounting officer will be posted on our website.
59
Corporate Governance Guidelines
We have adopted Corporate Governance Guidelines and Policies in accordance with the NYSE corporate
governance listing standards in effect as of the date of this Annual Report. A copy of our Corporate Governance
Guidelines is available without charge from our website at www.suburbanpropane.com or upon written request
directed to: Suburban Propane Partners, L.P., Investor Relations, P.O. Box 206, Whippany, New Jersey 07981-
0206.
Audit Committee Charter
We have adopted a written Audit Committee Charter in accordance with the NYSE corporate governance
listing standards in effect as of the date of this Annual Report. The Audit Committee Charter is reviewed
periodically to ensure that it meets all applicable legal and NYSE listing requirements. A copy of our Audit
Committee Charter is available without charge from our website at www.suburbanpropane.com or upon written
request directed to: Suburban Propane Partners, L.P., Investor Relations, P.O. Box 206, Whippany, New Jersey
07981-0206.
Compensation Committee Charter
Five Supervisors, who are not officers or employees of the Partnership or its subsidiaries, serve on the
Compensation Committee. We have adopted a Compensation Committee Charter in accordance with the NYSE
corporate governance listing standards in effect as of the date of this Annual Report. A copy of our
Compensation Committee Charter is available without charge from our website at www.suburbanpropane.com or
upon written request directed to: Suburban Propane Partners, L.P., Investor Relations, P.O. Box 206, Whippany,
New Jersey 07981-0206.
NYSE Annual CEO Certification
The NYSE requires the Chief Executive Officer of each listed company to submit a certification indicating
that the company is not in violation of the Corporate Governance listing standards of the NYSE on an annual
basis. Our then current Chief Executive Officer submitted his Annual CEO Certification for 2009 to the NYSE
without qualification.
60
ITEM 11. EXECUTIVE COMPENSATION
Compensation Discussion and Analysis
This Compensation Discussion and Analysis explains our executive compensation philosophy, policies and
practices with respect to the following executive officers of the Partnership (the “named executive officers”): the
Chief Executive Officer, the President, the Chief Financial Officer and the other three most highly compensated
executive officers. In accordance with a management succession plan developed by the Compensation
Committee of the Partnership’s Board of Supervisors and Mark Alexander, our Chief Executive Officer, Mr.
Alexander stepped down from his position as Chief Executive Officer of the Partnership at the conclusion of
fiscal 2009. At that time, Michael J. Dunn, Jr., our President, assumed the additional role of Chief Executive
Officer effective September 27, 2009 (the beginning of our fiscal 2010).
Executive Compensation Philosophy and Components
The objectives of our executive compensation program are as follows:
• The attraction and retention of talented executives who have the skills and experience required to
achieve our goals; and
• The alignment of the short-term and long-term interests of our executive officers with the short-term
and long-term interests of our Unitholders.
We accomplish these objectives by providing our executives with compensation packages that combine
various components that are specifically linked to either short-term or long-term performance measures.
Therefore, our executive compensation packages are designed to achieve our overall goal of sustainable,
profitable growth by rewarding our executive officers for behaviors that facilitate our achievement of this goal.
The principal components of the compensation we provide to our named executive officers are as follows:
• Base salary;
• Cash incentives paid under a performance-based annual bonus plan;
• Long-term Incentive Plan awards; and
• Discretionary awards of restricted units under the Restricted Unit Plans.
We align the short-term and long-term interests of our executive officers with the short-term and long-term
interests of our Unitholders by:
• Providing our executive officers with an annual incentive target that encourages them to achieve or
exceed targeted financial results and operating performance for the fiscal year;
• Providing a long-term incentive plan that encourages our executive officers to implement activities
and practices conducive to sustainable, profitable growth because it permits them to share in benefits
generated in the future; and
• Providing our executive officers with restricted units in order to retain the services of the
participating executive officers over a five-year period while simultaneously encouraging behaviors
conducive to the long-term appreciation of our Common Units.
Establishing Executive Compensation
The Compensation Committee (the “Committee”) is responsible for overseeing our executive compensation
program. In accordance with its charter, available on our website at www.suburbanpropane.com, the Committee
ensures that the compensation packages provided to our executive officers are designed in accordance with our
compensation philosophy. The Committee reviews and approves the compensation packages of our managing
61
directors, assistant vice presidents, vice presidents and our named executive officers.
Annually, our Senior Vice President of Administration prepares a comprehensive analysis of each executive
officer’s past and current compensation to assist the Committee in the assessment and determination of executive
compensation packages for the subsequent fiscal year. The Committee considers a number of factors in
establishing the compensation packages for each executive officer, including, but not limited to, tenure, scope of
responsibility and individual performance. The relative importance assigned to each of these factors by the
Committee may differ from executive to executive. The performance of each of our executive officers is
continually assessed by the Committee and by our highest-ranking executive officers and also factors into the
decision-making process, particularly in relation to promotions and increases in base compensation. In addition,
as part of the Committee’s annual review of each executive officer’s total compensation package, the Committee
was provided with benchmarking data for a relevant peer group of companies for comparison purposes. The
benchmarking data is just one of a number of factors considered by the Committee, but is not necessarily the
most persuasive factor.
The benchmarking data used in determining compensation for the 2009 fiscal year was derived from the
Mercer Human Resource Consulting, Inc. (“Mercer”) Benchmark Database containing information obtained from
surveys of over 2,500 organizations and approximately 200 positions which may include similarly-sized national
propane marketers. The Committee does not base its benchmarking solely on a peer group of other propane
marketers. The use of the Mercer database provides a broad base of compensation benchmarking information for
companies of a similar size to Suburban. The peer group used for the Suburban positions consisted of
organizations included in the Mercer database that report median annual revenues of between $1.0 billion and $4
billion per year.
The Committee believes that benchmarking against such companies in determining “total cash compensation
opportunities” is appropriate because of the proximity of the Partnership’s headquarters to New York City and
the need to realistically compete for skilled executives in an environment shared by numerous other enterprises
that seek skilled employees. For this reason, the Committee chooses not to base its benchmarking on the
compensation practices of other propane marketers due to the fact that the other, similarly-sized propane
marketers compete for employees in vastly different economic environments.
Alternatively, for the reasons below, the Committee decided to include all other propane marketers,
structured as publicly traded partnerships, in the peer group it selected for the 2003 Long-Term Incentive Plan
(for more on the 2003 Long-Term Incentive Plan, refer to the subheading “2003 Long-Term Incentive Plan”
below). Earning a payment under the 2003 Long-Term Incentive Plan is dependent upon the performance
(referred to in the plan document as “total return to unitholders”) of our Common Units in comparison to the unit
performance of a peer group of eleven other master limited partnerships over a three-year measurement period.
Because total return to unitholders is based on unit price appreciation and distributions, both of which are
impacted by earnings, this plan was implemented by the Committee to provide an incentive to management to
grow the business and to be conservative in regard to the management of expenses, among other things, and,
thereby, enhance the return that we provide to our investors. Because master limited partnerships are not
taxpaying entities, potentially these entities have more available cash to distribute to their investors than similar
businesses that operate as corporations and do pay corporate-level taxes. This sometimes enables master limited
partnerships to provide a greater return, in the form of cash distributions, to their investors than similarly situated
corporations. As a result of this reasoning, the Committee selected a peer group for the 2003 Long-Term
Incentive Plan that included other propane marketers.
In establishing the fiscal 2007 executive compensation packages, the Committee used the median total
compensation paid by the peer group to assess whether the “total cash compensation opportunities” that we
provide to our executive officers are both competitive and commensurate with each executive officer’s position
and corresponding duties. However, in establishing the executive compensation packages for subsequent fiscal
years, due to the Committee’s perception of the competitiveness of executive compensation packages provided to
62
executives in the New York area, the Committee used the mean of the reported data as its benchmark. Generally
speaking, the mean of the reported data is higher than the median. In recent fiscal years, the members of the
Committee have focused on lessening the shortfalls between the compensation packages that we provide to our
executive officers and the mean compensation paid by the companies whose data underlie the Mercer database.
The Committee does not, however, have a formal target with respect to the amount of the shortfall it is trying to
lessen. Moreover, the Committee does not set specific percentile targets for total compensation of our executive
officers compared to the total compensation of the peer group.
In making their decisions regarding our fiscal 2009 executive compensation packages, during the
Committee’s November 13, 2008 meeting, the members of the Committee reviewed the total cash compensation
opportunities that we provided to our executive officers during fiscal 2008. Each executive officer’s “total cash
compensation opportunities” consist of base salary, an annual cash bonus, and 2003 Long-Term Incentive Plan
awards. The Committee then compared each executive officer’s total cash compensation opportunity to the total
mean cash compensation opportunity for the parallel position in the Mercer study. By focusing on each
executive officer’s total cash compensation opportunities as a whole, instead of on single components of
compensation such as base salary, the Committee created fiscal 2009 compensation packages for our executive
officers that emphasize the performance-based components of compensation.
The Committee also met on July 22, 2009 to consider salary increases for seven of our executive officers
(four of whom are among our named executive officers) who assumed additional responsibilities as a result of
the administrative reorganization that occurred following our April 23, 2009 announcement that Mr. Dunn would
succeed Mr. Alexander as our Chief Executive Officer (while, at the same time, remaining as our President). Mr.
Dunn received a base salary increase (from $425,000 to $475,000) in recognition of his assumption of the
additional responsibilities of Chief Executive Officer; Mr. Stivala, our Chief Financial Officer, received a base
salary increase (from $260,000 to $275,000) in recognition of his assumption of responsibility for our
Information Services Department; Mr. Keating, our former Vice President of Human Resources, received a base
salary increase (from $225,000 to $260,000), an increased cash bonus percentage (from 65% to 70%) and was
promoted to Senior Vice President of Administration in recognition of his assumption of administrative
responsibilities for the entire enterprise; and Mr. Brinkworth, our Vice President of Product Supply, received a
base salary increase (from $225,000 to $245,000) in recognition of his assumption of responsibility for our Non-
Fuel Purchasing Department.
These base salary increases and Mr. Keating’s promotion became effective on August 1, 2009. Although the
cash incentives under our annual cash bonus plan and our Long-term Incentive Plan awards bear a formulaic
relationship to base salary, all fiscal 2009 cash incentive payments and Long-term Incentive Plan awards for
these seven executive officers were based upon the base salaries (and, in Mr. Keating’s case, bonus percentage)
approved by the Committee at its November 13, 2008 meeting. In anticipation of their July 22, 2009 meeting, the
members of the Committee conducted reviews that were similar to those conducted in anticipation of their
November 13, 2008 meeting. The Committee indicated that it will not consider base salary increases for the
seven executive officers who received base salary increases at its July 22, 2009 meeting until fiscal 2011 (unless
unforeseen circumstances arise that require special consideration).
Role of Executive Officers and Compensation Committee in Compensation Process
The Committee establishes and enforces our general compensation philosophy in consultation with our Chief
Executive Officer. The role of our Chief Executive Officer in the executive compensation process is to
recommend individual pay adjustments for the executive officers, other than himself, to the Committee based on
market conditions, our performance, and individual performance. With the assistance of our Senior Vice
President of Administration, our Chief Executive Officer presents the Committee with information comparing
each executive officer’s compensation to the mean compensation figures provided in the Mercer database.
63
The Partnership’s sole use of Mercer was to provide the Committee with benchmarking data. Therefore,
neither our Chief Executive Officer nor our President met with representatives from Mercer. The information
provided by Mercer was derived from a proprietary database maintained by Mercer and, as such, there was no
formal consultancy role played by them. The Committee believes that the Mercer benchmarking data, which is
provided to the Committee by our Senior Vice President of Administration, can be used by the Committee as an
objective benchmark on which decisions relative to executive compensation can be based. In the course of its
deliberations, the Committee compares the objective data obtained from the Mercer database to the internal
analyses prepared by our Senior Vice President of Administration.
Among other duties, the Committee has overall responsibility for:
• Reviewing and approving compensation of our Chief Executive Officer, President, Chief Financial
Officer and our other executive officers;
• Reporting to the Board of Supervisors any and all decisions regarding compensation changes for our
Chief Executive Officer, President, Chief Financial Officer and our other executive officers;
• Evaluating and approving our annual cash bonus plan, long-term incentive plan, restricted unit plan,
as well as all other compensation policies and programs;
• Administering and interpreting the compensation plans that constitute each component of our
executive officers’ compensation packages; and
• Engaging consultants, when appropriate, to provide independent, third-party advice on executive
officer-related compensation.
Allocation Among Components
Under our compensation structure, the mix of base salary, cash bonus and long-term compensation provided
to each executive officer varies depending on his or her position. The base salary for each executive officer is
the only fixed component of compensation. All other cash compensation, including annual cash bonuses and
long-term incentive compensation, is variable in nature as it is dependent upon achievement of certain
performance measures. The following tables summarize the components as percentages of each named executive
officer’s total cash compensation opportunity in fiscal 2009 (as determined at the Committee’s November 13,
2008 and July 22, 2009 meetings, respectively).
November 13, 2008 Meeting
Base Salary
Cash
Bonus Target
Long-Term
Incentive
Mark A. Alexander(1)
Michael A. Stivala
Michael J. Dunn, Jr.
Steven C. Boyd
Michael M. Keating
Douglas T. Brinkworth
43%
47%
40%
47%
50%
47%
43%
35%
40%
35%
33%
35%
14%
18%
20%
18%
17%
18%
(1) Mr. Alexander’s Long-Term Incentive Plan award was established per the terms of an agreement between Mr. Alexander
and the Partnership.
July 22, 2009 Meeting
Base Salary
Cash
Bonus Target
Long-Term
Incentive
Michael A. Stivala
Michael J. Dunn, Jr.
Michael M. Keating
Douglas T. Brinkworth
47%
40%
48%
45%
35%
40%
34%
36%
18%
20%
18%
19%
64
In allocating compensation among these components, we believe that the compensation of our senior-most
levels of management—the levels of management having the greatest ability to influence our performance—
should be at least 50% performance-based, while lower levels of management should receive a greater portion of
their compensation in base salary. Additionally, our short-term and long-term incentive plans do not provide for
minimum payments and are, thus, truly pay-for-performance compensation plans.
Internal Pay Equity
In determining the different compensation packages for each of our named executive officers, the Committee
takes into consideration a number of factors, including the level of responsibility and influence that each named
executive officer has over the affairs of the Partnership, tenure with the Partnership, individual performance and
years of experience in his or her current position. The relative importance assigned to each of these factors by
the Committee may differ from executive to executive. The Committee will also consider the existing level of
equity ownership of each of our named executive officers when granting awards under our Restricted Unit Plans
and the 2003 Long-Term Incentive Plan (see below for a description of these plans). The fiscal 2007, fiscal 2008
and fiscal 2009 compensation packages for our Chief Executive Officer and our President were set forth in their
respective employment agreements, as further described below. As a result, different weight may be given to
different components of compensation among each of our named executive officers. In addition, as discussed in
the section above titled “Allocation Among Components,” the compensation packages that we provide to our
senior-most levels of management are, at a minimum, 50% performance-based. In order to align the interests of
senior management with the interests of our Common Unitholders, we consider it requisite to accentuate the
performance-based elements of the compensation packages that we provide to these individuals because the
actions and decisions of these individuals have a direct impact on our performance.
Base Salary
Base salaries for the named executive officers and, indeed, all of our other executive officers, are reviewed
and approved annually by the Committee. In order to determine the fiscal 2009 base salary increases, the
Committee compared each executive officer’s fiscal 2008 base salary with the corresponding mean salary
provided in the Mercer database. The Committee determined base salary adjustments, which may be higher or
lower than the comparative data, following an assessment of our overall results as well as each executive
officer’s position, performance and scope of responsibility, while at the same time considering each executive
officer’s previous total cash compensation opportunities. At the beginning of fiscal 2009, each named executive
officer received adjustments to his base salary in accordance with the philosophy and process described above,
ranging from 0% to 6%. In the event of a promotion, a significant increase in an executive officer’s
responsibilities, or a new hire, the Committee reviews and takes action at its next meeting as it did at its July 22,
2009 meeting.
The fiscal 2009 adjustments to each named executive officer’s base salary were as follows:
November 13, 2008
July 22, 2009
Mark A. Alexander
Michael A. Stivala
Michael J. Dunn, Jr
Steven C. Boyd
Michael M. Keating
Douglas T. Brinkworth
0%(1)
4%
0%(1)
6%
2%
5%
n/a
6% (2)
12% (3)
n/a
16% (4)
9% (5)
(1) Because Mr. Alexander’s and Mr. Dunn’s base salaries were set forth under the provisions of their respective
employment agreements, the Committee did not adjust their base salaries on November 13, 2008.
65
(2) The Committee’s July 22, 2009 decision to increase Mr. Stivala’s salary by 6% was based on consideration
of his assuming responsibility for our Information Services Department.
(3) The Committee’s July 22, 2009 decision to increase Mr. Dunn’s salary by 12% was based on consideration
of his assuming the additional responsibilities as Chief Executive Officer, in addition to those of President.
(4) The Committee’s July 22, 2009 decision to increase Mr. Keating’s salary by 16% was based on consideration
of his assuming the increased responsibilities of Senior Vice President of Administration.
(5) The Committee’s July 22, 2009 decision to increase Mr. Brinkworth’s salary by 9% was based on
consideration of his assuming responsibility for our Non-Fuel Purchasing Department.
The total base salary paid to each named executive officer in fiscal 2009 is reported in the column titled
“Salary ($)” in the Summary Compensation Table below.
Annual Cash Bonus Plan
Annual cash bonuses (which fall within the SEC’s definition of “Non-Equity Incentive Plan Compensation”
for the purposes of the Summary Compensation Table and otherwise) are earned by our executive officers in
accordance with the performance objective provisions of our annual cash bonus plan. The cash bonuses earned
by Mr. Alexander and Mr. Dunn are the only exceptions to this general rule because their bonus provisions are
established in their respective employment agreements. Mr. Alexander’s employment agreement, which was
superseded by his separation and consulting agreement (for more information on Mr. Alexander’s separation and
consulting agreement, please refer to the section titled “Employment Agreements” below), provided for a
maximum annual cash bonus equal to his base salary whereas Mr. Dunn’s employment agreement provides for a
maximum annual cash bonus equal to 110% of his base salary. During fiscal 2007, in recognition of
performance, the Committee provided Mr. Alexander with a cash bonus payment of 110% of his base salary to
parallel the cash bonuses earned by the other named executive officers under our annual cash bonus plan. During
fiscal 2009, as part of the negotiated terms of Mr. Alexander’s separation and consulting agreement, the
Committee agreed to provide Mr. Alexander with a cash bonus payment of up to 110% of his base salary to
parallel the cash bonuses earned by the other named executive officers under our annual cash bonus plan. Mr.
Dunn has agreed with the Partnership to terminate his employment agreement effective as of the start of fiscal
2010; hereafter, Mr. Dunn’s annual cash bonus will, like those of the other executive officers, be governed by the
terms of our annual cash bonus plan.
Although our annual cash bonus plan is generally administered using the formula described below,
occasionally the Committee may exercise its broad discretionary powers to decrease or increase the annual cash
bonus paid to a particular executive officer when the Committee recognizes that a particular executive officer’s
performance warrants a decreased or an increased bonus. Such adjustments, if any, are recommended to the
Committee by our Chief Executive Officer. During fiscal 2009, our Chief Executive Officer did not make any
such recommendations to the Committee.
The terms of our annual cash bonus plan provide for cash payments of a specified percentage (which, in
fiscal 2009 ranged from 65% to 100%) of our named executive officers’ annual base salaries (“target cash
bonus”) if, for the fiscal year, actual EBITDA (as defined in Item 6, herein) equals the Partnership’s budgeted
EBITDA. For purposes of calculating the annual cash bonus, the Committee may exercise discretion to adjust
both budgeted and actual EBITDA for various items considered to be non-recurring in nature; including, but not
limited to, unrealized (non-cash) gains or losses on derivative instruments reported within cost of products sold
in our statement of operations and gains or losses on the disposal of discontinued operations (“cash bonus plan
EBITDA”). Executive officers have the opportunity to earn between 90% and 110% of their target cash bonuses,
in accordance with the terms of the plan, paralleling the percentage of actual cash bonus plan EBITDA in
relationship to budgeted cash bonus plan EBITDA ranging from 90% to 110%. Under the annual cash bonus
plan, no bonuses are earned if actual cash bonus plan EBITDA is less than 90% of budgeted cash bonus plan
EBITDA and cash bonuses cannot exceed 110% of the target cash bonus even if actual cash bonus plan EBITDA
is more than 110% of budgeted cash bonus plan EBITDA.
66
For fiscal 2009, our budgeted cash bonus plan EBITDA was $187 million. Our actual cash bonus plan
EBITDA was such that each of our executive officers earned 110% of his or her target cash bonus. The
following table provides the fiscal 2009 budgeted cash bonus plan EBITDA targets that were established at the
November 13, 2008 Compensation Committee meeting:
Fiscal 2009 Budgeted Cash
Bonus Plan EBITDA
(in Millions)
$205.7
$196.4
$187.0 (1)
$177.7
$168.3
Target Bonus Percentage that
would have been Earned if
Actual Cash Bonus Plan
EBITDA Equaled the Figure
in the Previous Column
110%
105%
100%
95%
90%
(1) Budgeted cash bonus plan EBITDA for fiscal 2009.
The bonuses earned under the annual cash bonus plan by each of our named executive officers are reported
in the column titled “Non-Equity Incentive Plan Compensation ($)” in the Summary Compensation Table below.
The 2009 target cash bonus percentages and target cash bonuses established for each named executive officer
and the actual cash bonuses earned by each of them during fiscal 2009 are summarized as follows:
2009 Target Cash
Bonus as a % of
Base Salary
Established by the
Committee at its
November 13,
2008 Meeting
100%
75%
100%
75%
65%
75%
Name
Mark A. Alexander(1)
Michael A. Stivala(2)
Michael J. Dunn, Jr.(1)
Steven C. Boyd
Michael M. Keating(3)
Douglas T. Brinkworth(2)
2009 Target Cash
Bonus
2009 Actual Cash
Bonus Earned
$450,000
$195,000
$425,000
$195,000
$146,250
$495,000
$214,500
$467,500
$214,500
$160,875
$168,750
$185,625
(1) Mr. Alexander’s and Mr. Dunn’s target cash bonuses were originally established by the terms of their respective
employment agreements. However, for fiscal 2009, as part of the negotiated terms of Mr. Alexander’s separation
and consulting agreement, the Committee agreed to provide Mr. Alexander with a cash bonus payment of up to
110% of his base salary to parallel the cash bonuses earned by the other named executive officers under our annual
cash bonus plan. Although Mr. Dunn received a salary increase that was approved by the Committee at its July 22,
2009 meeting, Mr. Dunn’s fiscal 2009 cash bonus payment was based upon his previous salary. See “Employment
Agreements” section below.
(2) Mr. Stivala’s and Mr. Brinkworth’s cash bonus payments were based upon the salaries set for them by the
Committee at its November 13, 2008 meeting.
(3) Mr. Keating’s fiscal 2009 cash bonus payment was based upon the salary and target cash bonus percentage set for
him by the Committee at its November 13, 2008 meeting. However, because of the action taken by the Committee at
its July 22, 2009 meeting, for fiscal 2010 his target cash bonus percentage will be 70%.
For purposes of establishing the cash bonus targets for fiscal 2009, the Committee reviewed and approved
our fiscal 2009 budgeted cash bonus plan EBITDA at its meeting on November 13, 2008. The budgeted cash
bonus plan EBITDA is developed annually using a bottom-up process factoring in reasonable growth targets
67
from the prior year performance, while at the same time attempting to reach a good balance between a target that
is reasonably achievable, yet not assured. As described above, executive officers have the opportunity to earn
between 90% and 110% of their target cash bonuses, paralleling the percentage of actual cash bonus plan
EBITDA in relationship to budgeted cash bonus plan EBITDA ranging from 90% to 110%. Over the past three
years, our actual cash bonus plan EBITDA was such that each of our executive officers earned 110%, 95%, and
110% of their respective target cash bonus for fiscal 2009, fiscal 2008, and fiscal 2007, respectively.
2003 Long-Term Incentive Plan
At the beginning of fiscal 2003, we adopted the 2003 Long-Term Incentive Plan (“LTIP-2”), a phantom unit
plan, as a principal component of our executive compensation program. While the annual cash bonus plan is a
pay-for-performance plan that focuses on our short-term financial goals, LTIP-2 is designed to motivate our
executive officers to focus on long-term financial goals. LTIP-2 measures the market performance of our
Common Units on the basis of total return to our Unitholders (“TRU”) during a three-year measurement period
commencing on the first day of the fiscal year in which an unvested award was granted and compares our TRU to
the TRU of each of the other members of a predetermined peer group, consisting solely of other master limited
partnerships, approved by the Committee. The predetermined peer group may vary from year-to-year, but for all
current awards, includes AmeriGas Partners, L.P., Ferrellgas Partners, L.P. and Inergy, L.P. (the other propane
master limited partnerships). Unvested awards are granted at the beginning of each fiscal year as a Committee-
approved percentage of each executive officer’s salary. Cash payouts, if any, are earned and paid at the end of
the three-year measurement period.
LTIP-2 is designed to:
• Align a portion of our executive officers’ compensation opportunities with the long-term goals of our
Unitholders;
• Provide long-term compensation opportunities consistent with market practice;
• Reward long-term value creation; and
• Provide a retention incentive for our executive officers and other key employees.
At the beginning of the three-year measurement period, each executive officer’s unvested award of phantom
units is calculated by dividing a predetermined percentage (which is 30% for Mr. Alexander and for all other
executive officers is 52%), established upon adoption of LTIP-2, of the executive officer’s target cash bonus by
the average of the closing prices of our Common Units for the twenty days preceding the beginning of the fiscal
year. At the end of the three-year measurement period, depending on the quartile ranking within which our TRU
falls relative to the other members of the peer group, our executive officers, as well as the other participants, all
of whom are key employees, will receive a cash payout equal to:
• The quantity of the participant’s phantom units multiplied by the average of the closing prices of our
Common Units for the twenty days preceding the conclusion of the three-year measurement period;
• The quantity of the participant’s phantom units multiplied by the sum of the distributions that would
have inured to one of our outstanding Common Units during the three-year measurement period; and
• The sum of the products of the two preceding calculations multiplied by: zero if our performance
falls within the lowest quartile of the peer group; 50% if our performance falls within the second
lowest quartile; 100% if our performance falls within the second highest quartile; and 125% if our
performance falls within the top quartile.
68
The three-year measurement period of the fiscal 2007 award ended simultaneously with the conclusion of
fiscal 2009. The TRU for the fiscal 2007 award fell within the highest quartile. The following is a summary of
the cash payouts related to the fiscal 2007 award earned by our named executive officers at the conclusion of
fiscal 2009.
Mark A. Alexander
Michael A. Stivala
Michael J. Dunn, Jr.
Steven C. Boyd
Michael M. Keating
Douglas T. Brinkworth
$ 252,479(1) (2)
$ 101,004(1)
$ 389,020(1)
$ 128,350(1)
$ 132,761(1)
$ 113,795(1)
(1) The cash payouts related to our named executive officers’ fiscal 2007 awards earned at the conclusion of fiscal 2009
is an additional disclosure that bears no meaningful relationship to the expense recognized during fiscal 2009 and
reported in column (e) of the Summary Compensation Table below.
(2) Mr. Alexander’s payment is considerably smaller than Mr. Dunn’s as a result of an agreement between Mr. Alexander
and the Partnership.
The following is a summary of the quantity of phantom units that signify the unvested awards granted to our
named executive officers during fiscal 2008 and fiscal 2009 that will be used to calculate cash payments at the
end of each respective award’s three-year measurement period (i.e., at the end of fiscal 2010 for the fiscal 2008
award and at the end of fiscal 2011 for the fiscal 2009 award):
Mark A. Alexander
Michael A. Stivala
Michael J. Dunn, Jr.
Steven C. Boyd
Michael M. Keating
Douglas T. Brinkworth
Fiscal
2008 Award
2,989
1,871
4,894
1,693
1,647
1,857
Fiscal
2009 Award
3,752
2,818
6,142
2,818
2,114
2,439
The peer group members selected by the Committee for the fiscal 2007, fiscal 2008 and fiscal 2009 awards
consist entirely of publicly-traded partnerships, inclusive of all propane-related partnerships. The Committee
decided upon this peer group because all publicly-traded partnerships have similar tax attributes and can, as a
result, distribute more cash than similarly-sized corporations generating similar revenues. The following table
lists, in alphabetical order, the names and ticker symbols of the peer group used to measure our performance
during the fiscal 2007, fiscal 2008 and fiscal 2009 LTIP-2 awards’ three-year measurement periods:
Fiscal 2007, Fiscal 2008 and Fiscal 2009 LTIP-2 Awards Peer Group
Peer Group Member Name
AmeriGas Partners, L.P.
Copano Energy, LLC
Crosstex Energy, L.P.
Dorchester Minerals, L.P.
Energy Transfer Partners, L.P.
Ferrellgas Partners, L.P.
Inergy, L.P.
MarkWest Energy Partners, L.P.
Plains All American Pipeline, L.P.
Star Gas Partners, L.P.
Sunoco Logistics Partners, L.P.
Ticker Symbol
APU
CPNO
XTEX
DMLP
ETP
FGP
NRGY
MWE
PAA
SGU
SXL
Formerly, the LTIP-2 plan document contained a retirement provision that provided for the immediate
termination of the three-year measurement period for all outstanding LTIP-2 awards held by a retirement-eligible
69
participant upon retirement. Under the former provisions, TRU was calculated as if the three-year measurement
period for each outstanding award ended on the participant’s retirement date in order to determine whether a
payment had been earned by the retiree. On January 24, 2008, the Committee amended the retirement provisions
of the plan document to provide that a retirement-eligible participant’s outstanding awards vest as of the
retirement-eligible date, but such awards remain subject to the same three-year measurement period for purposes
of determining the eventual cash payout, if any, at the conclusion of the measurement period.
Because the cash payments under the LTIP-2 are based on the value of our Common Units, compensation
expense generated by this plan is recognized ratably over the plan’s three-year measurement period; however, in
the case of awards held by retirement-eligible participants, compensation expense is recognized in full when the
unvested award is granted to the participant. As a result, because Mr. Dunn and Mr. Keating are, in accordance
with the plan’s retirement provisions retirement-eligible participants, the compensation expense for Mr. Dunn’s
and for Mr. Keating’s unvested awards appear higher than the compensation charges related to unvested awards
held by the other named executive officers, none of whom meet the plan document’s retirement criteria.
Therefore, the disparity in LTIP-2 compensation-related expense between the named executive officers who are
retirement-eligible participants and the named executive officers who are not is attributable to the accounting
requirements for the timing of expense recognition rather than to a disparity in actual compensation. In addition,
as part of the negotiated terms of Mr. Alexander’s separation and consulting agreement, Mr. Alexander’s
outstanding awards under the LTIP-2 vest as of September 26, 2009, but such awards remain subject to the same
three-year measurement period for purposes of determining the eventual cash payout, if any, at the conclusion of
the measurement period. As a result, it was necessary to recognize all remaining unrecognized expense
attributable to his unvested fiscal 2008 and fiscal 2009 awards during fiscal 2009. All such charges to this year’s
earnings relative to our named executive officers are reported in the column titled “Unit Awards ($)” in the
Summary Compensation Table below.
Restricted Unit Plans
2000 Restricted Unit Plan
We adopted the 2000 Restricted Unit Plan (“RUP”) effective November 1, 2000. Upon adoption, this plan
authorized the issuance of 487,805 Common Units to our executive officers, managers and other employees and
to the members of our Board of Supervisors. On October 17, 2006, following approval by our Unitholders, we
adopted amendments to the RUP which, among other things, increased the number of Common Units authorized
for issuance under the RUP by 230,000 for a total of 717,805. At the conclusion of fiscal 2009, there remained
37,397 restricted units available for future awards.
When the Committee authorizes an award of restricted units, the unvested units underlying an award do not
provide the grantee with voting rights and do not receive distributions or accrue rights to distributions during the
vesting period. Restricted unit awards vest as follows: 25% on each of the third and fourth anniversaries of the
grant date and the remaining 50% on the fifth anniversary of the grant date. Unvested awards are subject to
forfeiture in certain circumstances as defined in the RUP document. Upon vesting, restricted units are
automatically converted into our Common Units, with full voting rights and rights to receive distributions.
The RUP document previously contained a retirement provision that provided for the immediate vesting of
all unvested RUP awards held by a retiring participant who met all three of the following conditions on his or her
retirement date:
1. The unvested RUP award has been held by the grantee for at least six months;
2. The RUP grantee is age 55 or older; and
3. The RUP grantee has worked for us or one of our predecessors for at least 10 years.
70
On October 31, 2007, in order to comply with the regulations promulgated under Internal Revenue Code
(“IRC”) Section 409A, the Board of Supervisors amended the retirement provision to require a six-month delay
between a retirement eligible RUP participant’s retirement date and the date on which unvested RUP awards
vest.
All RUP awards are made at the discretion of the Committee. Because individual circumstances differ, the
Committee has not adopted a formulaic approach to making RUP awards. Awards are granted at the
Committee’s discretion when the need arises. Although the reasons for granting an award can vary, the objective
of granting an award to a recipient is twofold: to retain the services of the recipient over the five-year vesting
period while, at the same time providing the type of motivation that further aligns the long-term interests of the
recipient with the long-term interests of our Unitholders. The reasons for which the Committee grants RUP
awards include, but are not limited to, the following:
• To attract skilled and capable candidates to fill vacant positions;
• To retain the services of an employee;
• To provide an adequate compensation package to accompany an internal promotion; and
• To reward outstanding performance.
In determining the quantity of restricted units to grant to executive officers and other key employees, the
Committee considers, without limitation:
• The executive officer’s scope of responsibility, performance and contribution to meeting our
objectives;
• The total cash compensation opportunity provided to the executive officer for whom the award is
being considered;
• The value of similar equity awards to executive officers of similarly sized enterprises; and
• The current value of a similar quantity of outstanding Common Units.
In addition, in establishing the level of restricted units to grant to our executive officers, the Committee
considers the existing level of equity ownership by our executive officers and, prior to October 17, 2006, the
level of equity representation through management’s ownership of the then General Partner.
When the Committee decides to grant an equity award, it approves a dollar amount of equity compensation
that it wants to provide to a particular employee. This dollar amount is then converted into a quantity of
restricted units by dividing that dollar amount by the average of the closing prices of our Common Units for the
twenty trading days preceding the grant date. The Committee generally makes these awards at their first meeting
each year following the availability of the financial results for the prior fiscal year; however, occasionally the
Committee grants awards at other times of the year, particularly when the need arises to grant awards because of
promotions and new hires.
Until October 17, 2007, the grant date for RUP awards usually coincided with the Committee’s approval
date. However, on October 31, 2007, the Committee adopted a policy with respect to the effective grant date of
subsequent awards of restricted units under the RUP which states that:
Unless the Committee expressly determines otherwise for a particular award at the time of its approval of
such award, the effective date of grant of all awards of restricted units under the RUP in a given calendar
year will be the first business day in the month of December of that calendar year. If, at the discretion of
the Committee, an award is expressed as a dollar amount, then such award will be converted into the
number of restricted units, as of the effective date of grant, obtained by dividing the dollar amount of the
award by the average of the closing prices, on the New York Stock Exchange, of one Common Unit of
the Partnership for the 20 trading days immediately prior to that effective date of grant.
71
During fiscal 2009, RUP awards were granted to the following named executive officers:
Grant Date Quantity of Restricted Units
December 1, 2008
Michael A. Stivala
December 1, 2008
Steven C. Boyd
December 1, 2008
Michael M. Keating
Douglas T. Brinkworth December 1, 2008
4,818
2,570
4,818
3,212
At its November 13, 2008 meeting, Mr. Stivala, Mr. Boyd, Mr. Keating and Mr. Brinkworth were the only
named executive officers to whom the Committee granted RUP awards. All fiscal 2009 awards were made in
recognition of the exemplary performance of each of the recipients and as retention tools. In determining the
fiscal 2009 awards for Mr. Stivala, Mr. Boyd, Mr. Keating and Mr. Brinkworth, the Committee relied upon
information provided by Mercer to conclude that these awards were necessary to remediate shortfalls perceived
by the Committee in the cash compensation of these named executive officers. At its November 13, 2008
meeting, the Committee did not provide Mr. Alexander with a RUP award because, at the time, his compensation
was dictated by the provisions of his employment agreement. The Committee chose not to provide Mr. Dunn
with a fiscal 2009 award because his fiscal 2008 award was considerably higher than the quantities granted to the
other recipients of fiscal 2008 awards due to the Committee’s desire to recognize his responsibilities as President
and in consideration of his not having received any prior awards under the RUP. Because the Committee utilizes
RUP awards as a retention tool and because at the time Mr. Dunn received his fiscal 2008 RUP award he
satisfied the criteria found in the retirement provisions of the RUP document, the Committee exercised its
discretionary authority to make his award subject to the special stipulation that he hold his unvested award for
three years before the retirement provisions of the RUP document become applicable.
At its November 10, 2009 meeting, the Committee concluded an extensive review of Mr. Dunn’s
compensation relative to his assumption of additional responsibilities as the Partnership’s Chief Executive
Officer at the commencement of fiscal 2010. Because the Committee believes that equity compensation is a
critical component of executive compensation that helps to retain and motivate our executives, the Committee
concluded, after comparing the cash components of Mr. Dunn’s compensation to the Mercer study, that it would
be prudent to provide Mr. Dunn with a RUP award as of December 1, 2009, equal in value to $500,000, in
recognition of his assuming the responsibilities of our Chief Executive Officer. This RUP award will be
converted into a number of restricted units on the grant date using the formula set forth above.
Generally, compensation expense for unvested RUP awards is recognized ratably over the vesting periods
and is net of estimated forfeitures. However, when a RUP award is granted to a retirement-eligible individual,
compensation expense associated with such award is recognized ratably over the six-month period following the
grant date (because the RUP document requires that a retirement-eligible individual hold an unvested award for
at least six months before the award becomes subject to the plan document’s retirement provisions). Although
Mr. Dunn is a retirement-eligible participant, because the Committee stipulated that his fiscal 2008 award will
not become subject to the RUP document’s retirement provisions until the conclusion of fiscal 2012, the
compensation expense associated with Mr. Dunn’s fiscal 2008 award will be recognized ratably over the three-
year period between the grant date and the conclusion of fiscal 2012. Because Mr. Keating is retirement-eligible
participant whose fiscal 2009 award is subject to the normative retirement provisions of the RUP document, the
timing of compensation expense recognition associated with his fiscal 2009 RUP award was recognized ratably
over the six-month period following the grant date. As a result, all of the compensation expense associated with
Mr. Keating’s fiscal 2009 RUP award was recognized during fiscal 2009 and, therefore, was greatly accelerated
when contrasted to the recognition of compensation expense relative to the unvested RUP awards held by Mr.
Stivala, Mr. Boyd and Mr. Brinkworth who do not meet the retirement criteria of the plan document. The RUP-
related compensation expense recognized in the Partnership’s fiscal 2009 statement of operations, excluding
forfeiture estimates, on behalf of each of the named executive officers is reported in the column titled “Unit
Awards ($)” in the Summary Compensation Table below.
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2009 Restricted Unit Plan
At our July 22, 2009, Tri-Annual Meeting, our Unitholders approved our adoption of the 2009 Restricted
Unit Plan (“RUP-2”) effective August 1, 2009. This plan was adopted because the 2000 Restricted Unit Plan,
which terminates on October 31, 2010, had insufficient remaining units reserved for awards to meet our long
term compensation needs. Upon adoption, this plan authorized the issuance of 1,200,000 Common Units to our
executive officers, managers and other employees and to the members of our Board of Supervisors. At the
conclusion of fiscal 2009, no awards had been granted under this plan. The provisions of this plan are
substantially identical to those of the 2000 Restricted Unit Plan.
Recoupment of Incentive Compensation
On April 25, 2007, upon recommendation by the Committee, the Board of Supervisors approved an Incentive
Compensation Recoupment Policy which permits the Committee to seek the reimbursement from certain
executives of the Partnership and Operating Partnership of incentive compensation paid to those executives in
connection with any fiscal year for which there is a significant restatement of the published financial statements
of the Partnership triggered by a material accounting error, which results in less favorable results than those
originally reported by the Partnership. Such reimbursement can be sought from executives even if they had no
responsibility for the restatement. In addition to the foregoing, if the Committee determines that any fraud or
intentional misconduct by an executive was a contributing factor to the Partnership having to make a significant
restatement, then the Committee is authorized to take appropriate action against such executive, including
disciplinary action, up to, and including, termination, and requiring reimbursement of all, or any part, of the
compensation paid to that executive in excess of that executive’s base salary, including cancellation of any
unvested restricted units. The Incentive Compensation Recoupment Policy is available on our website at
www.suburbanpropane.com.
On July 31, 2007, the Board amended the annual cash bonus plan, LTIP-2 and the RUP to expressly make
future awards under such plans subject to the Incentive Compensation Recoupment Policy. RUP-2 was adopted
with provisions that made it subject to the Incentive Compensation Recoupment Policy.
Pension Plan
We sponsor a noncontributory defined benefit pension plan that was originally designed to cover all of our
eligible employees who met certain criteria relative to age and length of service. Effective January 1, 1998, we
amended the plan in order to provide for a cash balance format rather than the final average pay format that was
in effect prior to January 1, 1998. The cash balance format is designed to evenly spread the growth of a
participant’s earned retirement benefit throughout his or her career rather than the final average pay format,
under which a greater portion of a participant’s benefits were earned toward the latter stages of his or her career.
Effective January 1, 2000, we amended the plan to limit participation in this plan to existing participants and no
longer admit new participants to the plan. On January 1, 2003, we amended the plan to cease future service and
pay-based credits on behalf of the participants and, from that point on, participants’ benefits have increased only
due to interest credits.
Each of our named executive officers, with the exception of Mr. Stivala, participates in the plan. The
changes in the actuarial value relative to each named executive officer’s participation in the plan is reported in
the column titled “Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)” in the
Summary Compensation Table below.
Deferred Compensation
All employees, including the named executive officers, who satisfy certain service requirements, are entitled
to participate in our IRC Section 401(k) Plan (the “401(k) Plan”), in which participants may defer a portion of
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their eligible cash compensation up to the limits established by law. We offer the 401(k) Plan to attract and
retain talented employees by providing them with a tax-advantaged opportunity to save for retirement.
For fiscal 2009, all of our named executive officers participated in the 401(k) Plan. The benefits provided to
our named executive officers under the 401(k) Plan are provided on the same basis as to our other exempt
employees. Amounts deferred by our named executive officers under the 401(k) Plan are included in the column
titled “Salary ($)” in the Summary Compensation Table below.
In order to be competitive with other employers, if certain performance criteria are met, we will match our
employee-participants’ contributions up to the lesser of 6% of their base salary or $245,000, at a rate determined
based on a performance-based scale. The following chart shows the performance target criteria that must be met
for each level of matching contribution:
If We Meet This
Percentage of
Budgeted EBITDA(1)…
The Participating Employee
Will Receive this Matching
Contribution for the Year…
115% or higher
100% to 114%
90% to 99%
Less than 90%
100%
50%
25%
0%
(1) For additional information regarding the non-GAAP term “Budgeted EBITDA,” refer to the explanation
provided under the subheading “Annual Cash Bonus Plan” above.
For fiscal 2009, our budgeted 401(k) Plan EBITDA was $187.0 million. Our actual 401(k) Plan EBITDA
fiscal 2009 results were such that each of our executive officers earned a matching contribution of 100%. As a
result, we will provide participants with a match equal to 100% of their calendar year 2009 contributions that did
not exceed 6% of their total base pay up to a maximum base pay of $245,000. The matching contributions that
we will make on behalf of our named executive officers are reported in the column titled “All Other
Compensation ($)” in the Summary Compensation Table below.
Non-Qualified Deferred Compensation
Until January 2008, we maintained a Non-Qualified Deferred Compensation Plan (the “Compensation
Deferral Plan”) to which vested restricted units from the 1996 Restricted Unit Plan (which was subsequently
replaced by the 2000 Restricted Unit Plan described above) were deferred by the recipients, some of whom are
our named executive officers, on May 26, 1999 in connection with our Recapitalization. The Compensation
Deferral Plan operated through a rabbi trust, which held the deferred restricted units. On November 2, 2005, for
the purpose of IRC Section 409A compliance, our Board of Supervisors approved an amendment to the
Compensation Deferral Plan that prohibited any additional deferral elections.
At the end of fiscal 2007, Mr. Alexander and Mr. Dunn were the only remaining beneficiaries of the
Compensation Deferral Plan. In accordance with their deferral elections, the entire corpus of the rabbi trust was
distributed to them during January 2008 and the fair market value of their respective portions of the corpus is
included in their taxable wage earnings for calendar year 2008.
Because the Compensation Deferral Plan contained only Common Units, and because the cash distributions
that inured to those units were immediately distributed to the beneficiaries, the plan did not provide Mr.
Alexander and Mr. Dunn with above market interest; nor did they receive distributions on the Common Units at a
rate higher than the distributions paid on behalf of our Common Units held by the investing public. As a result,
74
nothing relative to the Compensation Deferral Plan is reported in the Summary Compensation Table below for
fiscal 2009, fiscal 2008 or fiscal 2007.
Supplemental Executive Retirement Plan
In 1998, we adopted a non-qualified, unfunded supplemental retirement plan known as the Suburban Propane
Company Supplemental Executive Retirement Plan (the “SERP”). The purpose of the SERP was to provide Mr.
Alexander and Mr. Dunn with a level of retirement income from us, without regard to statutory maximums,
including the IRC’s limitation for defined benefit plans. In light of the conversion of the Pension Plan to a cash
balance formula as described under the subheading “Pension Plan” above, the SERP was amended and restated
effective January 1, 1998. The annual retirement benefit under the SERP represents the amount of annual
benefits that the participants in the SERP would otherwise be eligible to receive, calculated using the same pay-
based credits referenced in the “Pension Plan” section above, applied to the amount of annual compensation that
exceeds the IRC’s statutory maximums for defined benefit plans, which was $200,000 in 2002. Effective
January 1, 2003, the SERP was discontinued with a frozen benefit determined for Mr. Alexander and Mr. Dunn.
When the SERP was adopted, prior to its being frozen, the plan was intended to provide Mr. Alexander with
a monthly benefit of $6,737 and Mr. Dunn with a monthly benefit of $373 upon retirement. In accordance with
the provisions of his separation and consulting agreement (for more information on Mr. Alexander’s separation
and consulting agreement, please refer to the section titled “Employment Agreements” below), Mr. Alexander
received a lump sum payment equal to what said lump sum payment would have been if Mr. Alexander had
attained age 55 and retired on September 26, 2009. The amount of Mr. Alexander’s payment was $444,030.
This amount was paid to Mr. Alexander during the thirty-day period following the conclusion of fiscal 2009. As
a result of this payment to Mr. Alexander, Mr. Dunn is the plan’s sole remaining participant. Because Mr.
Alexander was granted an additional four year’s interest credits (by September 26, 2009 he had attained age 51),
he received above market interest credits. The above-market interest credits allocated to Mr. Alexander have
been reported in the column titled “Change in Pension Value and Nonqualified Deferred Compensation
Earnings” in the Summary Compensation Table below. During fiscal 2009, Mr. Dunn received no above-market
interest credits relative to the SERP; therefore, nothing relative to Mr. Dunn’s participation in the SERP is
reported in the Summary Compensation Table below.
Other Benefits
As part of his total compensation package, each named executive officer is eligible to participate in all of our
other employee benefit plans, such as the medical, dental, group life insurance and disability plans. In each case,
with the exception of Mr. Alexander for whom we purchase supplemental life insurance and supplemental long-
term disability policies at a cost of $6,556 per year, these benefits are provided on the same basis as are provided
to other exempt employees. These benefit plans are offered to attract and retain talented employees by providing
them with competitive benefits.
Other than to Mr. Alexander, in accordance with the terms of his separation and consulting agreement that
superseded his employment agreement (both of which are described below in the section titled “Employment
Agreements”), and Mr. Dunn, in accordance with the terms of his employment agreement (described below in the
section titled “Employment Agreements”), there are no post-termination or other special rights provided to any
named executive officer to participate in these benefit programs other than the right to participate in such plans
for a fixed period of time following termination of employment, on the same basis as is provided to other exempt
employees, as required by law. As described below in the section titled “Employment Agreements,” Mr. Dunn
has agreed with the Partnership to terminate his employment agreement effective as of the commencement of
fiscal 2010.
The costs of all such benefits incurred on behalf of our named executive officers are reported in the column
titled “All Other Compensation ($)” in the Summary Compensation Table below.
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Perquisites
Perquisites represent a minor component of our executive officers’ compensation. Each of the named
executive officers is eligible for tax preparation services, a company-provided vehicle, and an annual physical.
The following table summarizes both the value and the utilization of these perquisites by the named executive
officers in fiscal 2009.
Name
Mark A. Alexander
Michael A. Stivala
Michael J. Dunn, Jr.
Steven C. Boyd
Michael M. Keating
Douglas T. Brinkworth
Tax Preparation
Services
$3,500
$ -0-
$3,000
$3,000
$3,000
$3,000
Employer-
Provided
Vehicle
$11,819
$11,318
$12,205
$ 6,205
$11,015
$10,610
Physical
$1,300
$1,300
$ -0-
$ -0-
$1,300
$ -0-
Perquisite-related costs are reported in the column titled “All Other Compensation ($)” in the Summary
Compensation Table below.
Impact of Accounting and Tax Treatments of Executive Compensation
As we are a partnership and not a corporation for federal income tax purposes, we are not subject to the
limitations of IRC Section 162(m) with respect to tax deductible executive compensation. Accordingly, none of
the compensation paid to our named executive officers is subject to a limitation as to tax deductibility. However,
if such tax laws related to executive compensation change in the future, the Committee will consider the
implications on us.
In accordance with their respective employment agreements, Mr. Alexander and Mr. Dunn were entitled to
receive tax gross-up payments for any parachute excise tax incurred pursuant to IRC Section 4999; they are also
entitled to receive tax gross-up payments for any payment that violates the provisions of IRC Section 409A or its
associated regulations.
On November 2, 2005, the Board of Supervisors approved an amendment to the Suburban Propane, L.P.
Severance Protection Plan for Key Employees (the “Severance Plan”) to provide that if any payment under the
Severance Plan subjects a participant to the 20% federal excise tax under IRC Section 409A, the payment will be
grossed up to permit such participant to retain a net amount on an after-tax basis equal to what he or she would
have received had the excise tax not been payable.
Mr. Alexander’s separation and consulting agreement does not meet the criteria under which IRC Section
4999 parachute excise tax is triggered. Additionally, it is the Partnership’s practice to comply with the statutory
and regulatory provisions of IRC Section 409A; therefore, all payments associated with Mr. Alexander’s
severance and consulting agreement will be made in accordance with the statutory and regulatory provisions of
IRC Section 409A and, as a result, will not incur the 20% federal excise tax triggered by payments that violate
said provisions.
Employment Agreements
Mr. Alexander, our Chief Executive Officer through the conclusion of fiscal 2009, and Mr. Dunn, our
President (and Chief Executive Officer commencing with the start of fiscal 2010), are the only executive officers,
named or otherwise, with whom we formerly had employment agreements. Mr. Alexander’s employment
agreement remained in effect until the conclusion of fiscal 2009 in accordance with the terms of his separation
and consulting agreement announced on April 23, 2009. At the conclusion of fiscal 2009, Mr. Alexander’s
76
employment agreement no longer had force or effect; instead, the provisions of his separation and consulting
agreement went into effect. For more information regarding Mr. Alexander’s separation and consulting
agreement, refer to the subsection below titled “Separation and Consulting Agreement of Mr. Alexander” and to
the table below titled “Actual Payments to Mr. Alexander under His Separation and Consulting Agreement.” As
a result of an agreement reached between Mr. Dunn and the Committee at its November 10, 2009 Committee
meeting, Mr. Dunn’s employment agreement was terminated retroactively as of September 27, 2009 and replaced
with a letter of agreement. For more information regarding Mr. Dunn’s letter of agreement, refer to the
subsection below titled “Letter of Agreement of Mr. Dunn” and to the table below titled “Potential Payments
upon Termination to Mr. Dunn under his Letter of Agreement.”
In regard to the history of Mr. Alexander’s employment agreement, we entered into an employment
agreement with him when it was announced, on March 5, 1996, that he would become our Chief Executive
Officer. This agreement was subsequently amended on October 23, 1997, April 14, 1999 and November 2, 2005.
In regard to the history of Mr. Dunn’s employment agreement, on February 5, 2007, we entered into an
employment agreement with him that had an effective date of February 1, 2007. On November 13, 2008, the
Committee approved an amendment to each of Mr. Alexander's and Mr. Dunn's employment agreements to bring
these agreements into conformance with the final regulations issued by the IRS under IRC Section 409A.
The final provisions of both Mr. Alexander’s and Mr. Dunn’s employment agreements were the results of
negotiations between the Committee and each individual and are not reducible to a specific process. For
example, Mr. Alexander was the only Chief Executive Officer that had been employed by the Partnership until
Mr. Dunn assumed the role on September 27, 2009. As a result, some aspects of Mr. Alexander’s employment
arrangements predate the existence of the Partnership and were agreed to by our former general partner. Over the
years, when considering whether to renew Mr. Alexander’s contract, the Committee considered, among other
factors, Mr. Alexander’s experience, performance and the fact that our headquarters are located in the New York
Metropolitan area. Similar considerations applied to the circumstances under which Mr. Dunn’s employment
agreement was negotiated. In particular, the Committee believed that the termination and change of control
arrangements contained in both of these employment agreements were an important part of the competitive total
compensation provided to our Chief Executive Officer and to our President. The Committee also believed that
the termination and change of control provisions of Mr. Alexander’s and Mr. Dunn’s employment agreements
were necessary to eliminate, or at least reduce, the possibility of reluctance on the part of our Chief Executive
Officer and our President to pursue potential change of control transactions that might have been in the best
interests of our Unitholders. These arrangements did not affect any decision made in fiscal 2009 with respect to
any other compensation elements for our named executive officers.
Employment Agreement of Mr. Alexander
Mr. Alexander’s employment agreement had an initial term of three years, and was renewed automatically
for all successive one-year periods through the end of fiscal 2009. The employment agreement provided for an
annual base salary of $450,000 and provided Mr. Alexander with the opportunity to earn a cash bonus of up to
100% of base salary based upon the achievement of the same EBITDA-related performance criteria as contained
in our annual cash bonus plan described in the section titled “Annual Cash Bonus Plan” above. Under our
Partnership Agreement, the Committee had the authority to grant Mr. Alexander a bonus in excess of 100% if, in
accordance with the terms of the annual cash bonus plan, our other executive officers earned bonuses exceeding
their target bonuses for the fiscal year. The Committee exercised this authority in connection with Mr.
Alexander’s cash bonus for fiscal 2007 in recognition of performance. For fiscal 2009, in accordance with the
provisions of Mr. Alexander’s separation and consulting agreement, the Committee agreed to provide Mr.
Alexander with a cash bonus payment of up to 110% of his base salary to parallel the cash bonuses earned by the
other named executive officers under our annual cash bonus plan.
Mr. Alexander’s employment agreement provided him the opportunity to participate in benefit plans made
available to our other executive officers and our other key employees. Under the provisions of this agreement,
77
we also provided Mr. Alexander with a term life insurance policy with a face amount equal to three times his
base salary.
If, while Mr. Alexander’s employment agreement had force and effect, a change of control (as defined in the
“Change of Control” section below) of the Partnership had occurred, and within six months prior thereto or at
any time subsequent to such change of control, we had terminated Mr. Alexander’s employment without cause
(as defined in the “Severance Benefits” section below) or if Mr. Alexander had resigned with good reason (as
defined in the “Severance Benefits” section below) or had terminated his employment commencing on the six
month anniversary and ending on the twelve month anniversary of such change of control, then Mr. Alexander
would have been entitled to:
• A lump sum severance payment equal to three times his annual base salary in effect as of the date of
termination plus three times his annual cash bonus at 100%; and
• Medical benefits for three years from the date of such termination.
In situations unconnected to a change of control event, if the Partnership had terminated Mr. Alexander’s
employment without cause or if Mr. Alexander had resigned with good reason, then Mr. Alexander would have
been entitled to:
• A severance payment equal to (A) the portion of his base salary earned but not paid as of the date of
termination, (B) his pro-rata annual cash bonus under the employment agreement based upon the
number of days worked during the fiscal year of termination, and (C) three times his annual base
salary in effect as of the date of termination; and
• Medical benefits for three years from the date of such termination reduced to the extent comparable
benefits are provided to Mr. Alexander by another party.
The employment agreement required that if any payment received by Mr. Alexander had been subject to the
20% excise tax under IRC Section 4999, the payment would have been increased to permit Mr. Alexander to
retain a net amount on an after-tax basis equal to what he would have received had the excise tax not been
payable.
If Mr. Alexander’s employment had been terminated due to death, disability, or pursuant to delivery of a non-
renewal notice to the Partnership in accordance with the terms and conditions of his employment agreement, he
or his estate would have been entitled to earned but unpaid base salary plus his pro-rata cash bonus. If his
employment had been terminated by the Partnership for cause, he would have been entitled to his earned but
unpaid base salary only.
Separation and Consulting Agreement of Mr. Alexander
In order to provide for an orderly transition from his leadership as our Chief Executive Officer to that of his
successor, after making his decision to resign as our Chief Executive Officer, Mr. Alexander entered into
negotiations with the Board of Supervisors to plan an orderly transition. As a result of negotiations between Mr.
Alexander and the Board of Supervisors, Mr. Alexander agreed to a termination of his existing employment
agreement simultaneous with Mr. Dunn’s succession as our next Chief Executive Officer at the close of business
on September 26, 2009. The following items are the essential elements of Mr. Alexander’s separation and
consulting agreement that was entered into as a result of Mr. Alexander’s and the Board of Supervisor’s
collaborative efforts to ensure an orderly transition:
• Mr. Alexander was to remain our Chief Executive Officer until the close of business on September 26,
2009. At that time, Mr. Dunn would succeed him as our President and Chief Executive Officer. Mr.
Alexander agreed not to stand for election to our Board of Supervisors at the July 22, 2009 Tri-Annual
Meeting.
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• Mr. Alexander’s existing employment agreement was to remain in effect until the end of fiscal 2009 and
subsequently have no further force or effect. During the period between April 23, 2009 and September
26, 2009, the Board of Supervisors would retain the right to terminate the existing agreement for cause.
During the period between April 23, 2009 and September 26, 2009, Mr. Alexander was permitted to seek
other employment opportunities that were not inconsistent with the non-compete provisions of his
separation and consulting agreement.
• Mr. Alexander will remain bound to non-competition, non-solicitation and confidentiality obligations
substantially identical to those contained in his former employment agreement, in each case, for the three
year period commencing at the close of business on September 26, 2009.
• For the three year period commencing at the close of business on September 26, 2009, Mr. Alexander
will remain engaged by the Partnership as an independent consultant providing transitional assistance
and strategic advice to the Board of Supervisors and to Mr. Dunn with respect to operational matters,
acquisitions, dispositions and other transactional matters.
• As payment for his three-year consulting services, Mr. Alexander will receive an aggregate consulting
fee of $1,000,000, payable over the course of the three-year consulting period.
• Mr. Alexander will be paid his fiscal 2009 cash bonus (110% of base salary), without proration.
• Mr. Alexander received a payment ($444,030) under the SERP equal to what said payment would have
been if Mr. Alexander had attained age 55 on September 26, 2009.
• Mr. Alexander will be reimbursed for income tax preparation services for the filing of his 2009, 2010
and 2011 income tax returns.
• We will continue to pay the lease expense and insurance on Mr. Alexander’s employer-provided vehicle
for the three years during which he acts as a consultant.
• We will pay for Mr. Alexander’s supplemental life insurance coverage for the three years during which
•
he acts as a consultant.
In lieu of a fiscal 2009 matching contribution of $14,700 to Mr. Alexander’s 401(k), Mr. Alexander will
receive a cash payment of $14,700 on or about the same day that fiscal 2009 matching contributions are
made to the 401(k) accounts of the Partnership’s employees.
• We will reimburse Mr. Alexander’s payments for medical and dental benefits coverage until he is
covered under another employer’s medical/dental plan for a period not to exceed the three year
consulting period.
• Mr. Alexander has provided us with a general release from future litigation. He will retain his rights to
indemnification and to director and officer insurance.
• Mr. Alexander transferred his sole membership interest in the general partner to Mr. Dunn at the close of
business on September 26, 2009.
• The change of control benefits under Mr. Alexander’s existing employment agreement terminated at the
close of business on September 26, 2009. However, if a change of control occurs during the three year
period during which he provides consulting services to us, his consulting obligations will cease and he
will be paid the remaining, unpaid portion of the agreed upon consulting fee of $1,000,000. In addition,
he will receive payment of any unpaid LTIP-2 awards in accordance with the terms and conditions of the
plan document.
For comparative purposes, the section titled “Potential Payments Upon Termination” below includes a table
containing hypothetical severance payments that would have been made under Mr. Alexander’s former
employment agreement and another containing the actual payments he will receive under his separation and
consulting agreement.
Employment Agreement of Mr. Dunn
Mr. Dunn’s employment agreement had an initial term of two years commencing on February 1, 2007, the
term of which were to automatically renew for successive one-year periods, unless earlier terminated by us or by
Mr. Dunn or otherwise terminated in accordance with the terms of the employment agreement. The provisions of
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Mr. Dunn’s employment agreement provided for an initial annual base salary of $400,000 per year (which was
permitted to be adjusted upwards annually at the Committee’s discretion) and, in accordance with the provisions
of our annual cash bonus plan, the opportunity to earn a cash bonus in each fiscal year up to 110% of his annual
base salary for each fiscal year (the “Maximum Annual Cash Bonus”). Additionally, Mr. Dunn’s employment
agreement permitted his participation in the same benefit plans made available to our other executive officers and
other key employees.
If, while Mr. Dunn’s employment agreement had force and effect, a change of control (as defined in the
“Change of Control” section below) of the Partnership had occurred and within six months prior thereto or within
two years thereafter the Partnership had terminated Mr. Dunn’s employment without cause (as defined in the
“Severance Benefits” section below) or if Mr. Dunn had resigned with good reason (as defined in the “Severance
Benefits” section below), then Mr. Dunn would have been entitled to a severance payment equal to the sum of:
• The portion of his base salary earned but not paid as of the date of termination;
• His pro-rata cash bonus (the bonus Mr. Dunn would have been entitled to under the employment
agreement for the full fiscal year in which the termination occurred multiplied by the number of days
from the beginning of that fiscal year until the termination date and divided by 365);
• Two times the sum of (1) his annual base salary in effect as of the date of termination, plus (2) the
Maximum Annual Cash Bonus; and
• Medical benefits for two years from the date of such termination.
In situations unconnected to a change of control event, if the Partnership had terminated Mr. Dunn’s
employment without cause, or if Mr. Dunn had resigned with good reason, then Mr. Dunn would have been
entitled to:
• A severance payment equal to (A) the portion of his base salary earned but not paid as of the date of
termination, (B) the annual cash bonus Mr. Dunn would have been entitled to under the employment
agreement for the full fiscal year in which the termination occurred had Mr. Dunn remained
employed by the Partnership for that full fiscal year, and (C) two times his annual base salary in
effect as of the date of termination; and
• Medical benefits for two years from the date of such termination.
The employment agreement required that if any payment received by Mr. Dunn had been subject to the 20%
excise tax under IRC Section 4999, the payment would have been increased to permit Mr. Dunn to retain a net
amount on an after-tax basis equal to what he would have received had the excise tax not been payable.
If Mr. Dunn’s employment had been terminated due to death, disability, or pursuant to delivery of a non-
renewal notice to the Partnership in accordance with the terms and conditions of his employment agreement, he
or his estate, as the case may be, would have been entitled to earned but unpaid base salary plus his pro-rata cash
bonus for the fiscal year during which termination occurred. If his employment were terminated by the
Partnership for cause, or if he resigned without good reason, he would have been entitled to his earned but unpaid
base salary only.
Letter of Agreement of Mr. Dunn
Simultaneous with the commencement of fiscal 2010, Mr. Dunn’s employment agreement was terminated
and replaced with a letter of agreement governing retirement and the implementation of a mutually agreed upon
succession plan. The letter of agreement between Mr. Dunn and us is summarized as follows:
• Mr. Dunn will participate in our Severance Protection Plan at the 78-week participation level.
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•
If on or after the last day of fiscal 2012, Mr. Dunn retires or leaves as a result of an agreed-upon
succession plan, he will receive the following:
o A lump sum payment equal to two years of base salary.
o Payment of medical benefits until attainment of age 65 (Mr. Dunn will be 63 at the conclusion of
fiscal 2012).
o Payment of unvested LTIP-2 awards held by Mr. Dunn at separation in accordance with the
terms and conditions of the LTIP-2 plan document.
o Transfer of ownership of employer-provided vehicle to Mr. Dunn.
o Receipt of other vested and certain unvested benefits including restricted unit awards, earned
cash bonus, pension plan in accordance with the terms and conditions of each plan.
In return for the foregoing, Mr. Dunn agreed to provide us with a release of all claims he might have against
us at the time of his departure. Mr. Dunn also agreed to provide us with transition consultation services for a
period not to exceed two years following his departure. Mr. Dunn will not be deemed to have retired or
terminated his employment if he simply relinquishes the title and responsibilities of President but remains our
Chief Executive Officer.
For comparative purposes, the section titled “Potential Payments Upon Termination” below includes a table
containing hypothetical severance payments that would have been made under the provisions Mr. Dunn’s former
employment agreement and another containing hypothetical payments under the provisions of his letter of
agreement.
Severance Benefits
We believe that, in most cases, employees should be paid reasonable severance benefits. Therefore, it is the
general policy of the Committee to provide executive officers and other key employees who are terminated by us
without cause or who choose to terminate their employment with us for good reason with a severance payment
equal to, at a minimum, one year’s base salary, unless circumstances dictate otherwise. This policy was adopted
because it may be difficult for former executive officers and other key employees to find comparable
employment within a short period of time. However, depending upon individual facts and circumstances,
particularly the severed employee’s tenure with us, the Committee may make exceptions to this general policy.
A “key employee” is an employee who has attained a director level pay-grade or higher. “Cause” will be
deemed to exist where the individual has been convicted of a crime involving moral turpitude, has stolen from us,
has violated his or her non-competition or confidentiality obligations, or has been grossly negligent in fulfillment
of his or her responsibilities. “Good reason” generally will exist where an executive officer’s position or
compensation has been decreased or where the employee has been required to relocate.
Change of Control
Our executive officers and other key employees have built the Partnership into the successful enterprise that
it is today; therefore, we believe that it is important to protect them in the event of a change of control. Further,
it is our belief that the interests of our Unitholders will be best served if the interests of our executive officers are
aligned with them, and that providing change of control benefits should eliminate, or at least reduce, the
reluctance of our executive officers to pursue potential change of control transactions that may be in the best
interests of our Unitholders. Additionally, we believe that the severance benefits provided to our executive
officers and to our key employees are consistent with market practice and appropriate because these benefits are
an inducement to accepting employment and because the executive officers have agreed to and are subject to
non-competition and non-solicitation covenants for a period following termination of employment. Therefore,
our executive officers and other key employees are provided with employment protection following a change of
control (the “Severance Protection Plan”). During fiscal 2009, our Severance Protection Plan covered all
executive officers, including the named executive officers, with the exception of our Chief Executive Officer and
81
our President, whose severance provisions were established in their respective employment agreements.
The Severance Protection Plan provides for severance payments of either sixty-five or seventy-eight weeks of
base salary and target cash bonuses for such officers and key employees following a change of control and
termination of employment. All named executive officers who participate in the Severance Protection Plan are
eligible for seventy-eight weeks of base salary and target bonuses. The cash components of any change of control
benefits are paid in a lump sum.
In addition, upon a change of control, without regard to whether a participant’s employment is terminated, all
unvested awards granted under the RUP will vest immediately and become distributable to the participants and
all outstanding, unvested LTIP-2 awards will vest immediately as if the three-year measurement period for each
outstanding award concluded on the date the change of control occurred and our TRU was such that, in relation
to the performance of the other members of the peer group, it fell within the top quartile.
For purposes of these benefits, a change of control is deemed to occur, in general, if:
• An acquisition of our Common Units or voting equity interests by any person immediately after
which such person beneficially owns more than 30% of the combined voting power of our then
outstanding Common Units, unless such acquisition was made by (a) us or our subsidiaries, or any
employee benefit plan maintained by us, our Operating Partnership or any of our subsidiaries, or (b)
any person in a transaction where (A) the existing holders prior to the transaction own at least 50%
of the voting power of the entity surviving the transaction and (B) none of the Unitholders other than
Suburban, our subsidiaries, any employee benefit plan maintained by us, our Operating Partnership,
or the surviving entity, or the existing beneficial owner of more than 25% of the outstanding
Common Units owns more than 25% of the combined voting power of the surviving entity (such
transaction, a “Non-Control Transaction”); or
• The consummation of (a) a merger, consolidation or reorganization involving Suburban other than a
Non-Control Transaction; (b) a complete liquidation or dissolution of Suburban; or (c) the sale or
other disposition of 40% or more of the gross fair market value of all the assets of Suburban to any
person (other than a transfer to a subsidiary).
The SERP (as discussed above in the section titled “Supplemental Executive Retirement Plan”) will
terminate effective on the close of business thirty days following the change of control. Mr. Dunn, the
remaining participant, will be deemed to have retired and will have his respective benefits determined as of the
date the plan is terminated with payment of his benefits no later than ninety days after the change of control. He
will receive a lump sum payment equivalent to the present value of his benefit payable under the plan utilizing
the lesser of the prime rate of interest as published in the Wall Street Journal as of the date of the change of
control or one percent, as the discount rate to determine the present value of the accrued benefit.
For purposes of the SERP, a change of control is deemed to occur, in general, if:
• An acquisition of our Common Units or voting equity interests by any person immediately after
which such person beneficially owns more than 25% of the combined voting power of our then
outstanding Common Units, unless such acquisition was made by (a) us or our subsidiaries,
Suburban Energy Services Group, LLC, or any employee benefit plan maintained by us, our
Operating Partnership or any of our subsidiaries, or (b) any person in a transaction where (A) the
existing holders prior to the transaction own at least 60% of the voting power of the entity surviving
the transaction and (B) none of the Unitholders other than the Partnership, our subsidiaries, any
employee benefit plan maintained by us, our Operating Partnership, or the surviving entity, or the
existing beneficial owner of more than 25% of the outstanding Common Units owns more than 25%
of the combined voting power of the surviving entity (such transaction, a “Non-Control
Transaction”); or
82
• Approval by our partners of (a) a merger, consolidation or reorganization involving the Partnership
other than a Non-Control Transaction; (b) a complete liquidation or dissolution of the Partnership; or
(c) the sale or other disposition of 50% or more of our net assets to any person (other than a transfer
to a subsidiary).
For additional information pertaining to severance payable to our named executive officers following a
change of control-related termination, see the tables titled “Potential Payments Upon Termination” below.
Report of the Compensation Committee
The Compensation Committee has reviewed and discussed with management this Compensation Discussion
and Analysis. Based on its review and discussions with management, the Committee recommended to the Board
of Supervisors that this Compensation Discussion and Analysis be included in this Annual Report on Form 10-K
for fiscal 2009.
The Compensation Committee:
John Hoyt Stookey, Chairman
John D. Collins
Harold R. Logan, Jr.
Dudley C. Mecum
Jane Swift
83
ADDITIONAL INFORMATION REGARDING EXECUTIVE COMPENSATION
Summary Compensation Table for Fiscal 2009
The following table sets forth certain information concerning the compensation of each named executive
officer during the fiscal years ended September 26, 2009, September 27, 2008 and September 29, 2007:
Name and Principal
Position
(a)
Year
(b)
Salary
($)(1)
(c )
Bonus
($)(2)
(d)
Change in
Pension Value
and
Nonqualified
Deferred
Compensation
Earnings
($)(5)
(h)
Unit
Awards
($)(3)
(e)
Non-Equity
Incentive Plan
Compensation
($)(4)
(g)
All Other
Compensation
($)(6)
(i)
Total
($)
(j)
2009
$450,000
-
$367,525
$495,000
$ 64,042
$1,126,693
$2,503,260
2008
$450,000
-
$171,606
$427,500
2007
$450,000
$ 45,000
$410,238
$456,188
Mark A. Alexander
Chief Executive Officer
Michael A. Stivala
Chief Financial Officer &
Chief Accounting Officer
Michael J. Dunn, Jr.
President
Steven C. Boyd
Vice President of Field
Operations
Michael M. Keating
Senior Vice President of
Administration
Douglas T. Brinkworth
Vice President of Product
Supply
2009
$262,500
2008
$250,000
2007
$200,000
2009
$433,333
2008
$425,000
2007
$391,552
2009
$260,000
2008
$245,000
2007
$226,232
2009
$230,833
2008
$220,000
2007
$210,000
2009
$228,333
2008
$215,000
2007
$195,000
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
$ 46,926
$1,096,032
$ 52,507
$1,413,933
$ 41,728
$ 748,753
$ 32,589
$ 594,877
$ 32,356
$ 575,557
$230,025
$214,500
$157,913
$154,375
$210,370
$132,831
$719,286
$467,500
$ 56,050
$ 48,065
$1,724,234
$498,395
$403,750
-
$ 38,976
$1,366,121
$824,713
$443,568
$ 6,752
$ 44,879
$1,711,464
$243,600
$214,500
$ 53,577
$ 39,811
$ 811,488
$178,116
$139,650
$243,910
$155,868
-
-
$ 26,406
$ 589,172
$ 34,202
$ 660,212
$218,072
$160,875
$ 107,821
$ 45,583
$ 763,184
$290,955
$135,850
-
$ 35,109
$ 681,914
$266,908
$151,611
$ 5,648
$ 43,816
$ 677,983
$203,655
$185,625
$ 31,679
$ 43,440
$ 692,732
$148,463
$153,188
-
$ 34,881
$ 551,532
$213,167
$129,758
-
$ 41,720
$ 579,645
(1) Includes amounts deferred by named executive officers as contributions to the qualified 401(k) Plan. For more information on Mr. Alexander’s and
Mr. Dunn’s base salaries, refer to the subheading titled “Employment Agreements” in the “Compensation Discussion and Analysis” above. During
fiscal 2007, Mr. Stivala was not our Chief Financial Officer. His promotion from Controller to Chief Financial Officer was effective on September
30, 2007; therefore, the $50,000 increase between his fiscal 2007 and fiscal 2008 base salary is attributable to the increased responsibilities associated
with his promotion.
For more information on the relationship between salaries and other cash compensation (i.e., annual cash incentives and 2003 Long-Term Incentive
Plan awards), refer to the subheading titled “Allocation Among Components” in the “Compensation Discussion and Analysis” above.
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(2) For fiscal 2007, in recognition of performance, the Committee provided Mr. Alexander with an incentive payment equal to 110% of his target cash
bonus to parallel the cash bonuses earned by the other named executive officers under the annual cash bonus plan. The amount reported in this
column represents the additional 10% awarded to Mr. Alexander at the Committee's discretion. For fiscal 2009, as part of the negotiated terms of Mr.
Alexander’s separation and consulting agreement, the Committee agreed to provide Mr. Alexander with a cash bonus payment of up to 110% of his
base salary to parallel the cash bonuses earned by the other named executive officers under our annual cash bonus plan. Because the additional 10%
for 2009 was pursuant to a written agreement (i.e., Mr. Alexander’s separation and consulting agreement), this amount has been reported in column
‘g’.
(3) The amounts reported in this column represent the expense, before the application of forfeiture estimates, recognized in our fiscal 2009, 2008 and 2007
statements of operations with respect to RUP awards made in fiscal years 2009, 2008 and 2007, as well as in prior fiscal years, and for LTIP-2 awards
made in fiscal years 2009, 2008 and 2007 as well as in prior fiscal years. The specific details regarding these plans are provided in the preceding
“Compensation Discussion and Analysis” under the subheadings “2000 Restricted Unit Plan” and “2003 Long-Term Incentive Plan.” The
breakdown for each plan with respect to each named executive officer is as follows:
Plan Name
2009
RUP
LTIP-2
Total
2008
RUP
LTIP-2
Total
2007
RUP
LTIP-2
Totals
Mr. Alexander
Mr. Stivala
Mr. Dunn
Mr. Boyd
Mr. Keating
Mr. Brinkworth
$ N/A
367,528
$ 367,528
$ 105,677
124,348
$ 230,025
$ 337,490
381,796
$ 719,286
$ 111,438
132,162
$ 243,600
$ 87,177
130,895
$ 218,072
$ 80,802
122,853
$ 203,655
N/A
$ 171,606
$ 171,606
N/A
$ 410,238
$ 410,238
$ 81,983
75,930
$ 157,913
$ 309,366
189,029
$ 498,395
$ 94,480
83,636
$ 178,116
$ 160,358
130,597
$ 290,955
$ 65,106
83,357
$ 148,463
$ 82,507
127,863
$ 210,370
N/A
$ 824,713
$ 824,713
$ 87,127
156,783
$ 243,910
$ 39,911
226,997
$ 266,908
$ 73,536
139,631
$ 213,167
Because Mr. Dunn has met the retirement eligibility criteria under the provisions of LTIP-2, all compensation expense relative to unvested awards
granted to Mr. Dunn under this plan was recognized in full in the year the award is granted. Although Mr. Dunn has also met the retirement eligibility
criteria under the RUP’s normative retirement provisions, at the discretion of the Committee, Mr. Dunn’s unvested fiscal 2008 RUP award must be
held for three years from the grant date of December 3, 2007 before the retirement provisions become applicable. As a result, the expense associated
with Mr. Dunn’s fiscal 2008 RUP award will be recognized over this three year period. Mr. Dunn’s December 3, 2007 RUP award of 29,533 units
was granted in consideration of his responsibilities as the Partnership’s President and in consideration of his not having received a prior award under
this plan.
Because Mr. Keating satisfied the RUP and LTIP-2 retirement criteria during fiscal 2008, all remaining unrecognized expense relative to unvested
awards held by him in fiscal 2008 was recognized during fiscal 2008. Additionally, all compensation expense relative to unvested awards granted to
Mr. Keating during fiscal 2009 was fully recognized during fiscal 2009.
(4) For fiscal 2009 and fiscal 2008, the amounts reported in this column represent each named executive officer's annual cash bonus earned in accordance
with the performance measures discussed under the subheading “Annual Cash Bonus Plan” in the “Compensation Discussion and Analysis.” For
fiscal 2007, the amounts included in this column also include the interest credits made on behalf of the remaining balances of LTIP-2’s predecessor
plan. Because the remaining balances of the predecessor plan were distributed to the participants during November 2007, there were no fiscal 2009 or
fiscal 2008 interest credits. The fiscal 2007 breakdown for each plan with respect to each named executive officer is as follows:
Plan Name
Cash Bonus
LTIP-1 Interest Credits
Totals
Mr. Alexander
$ 450,000
6,188
$ 456,188
Mr. Stivala
$ 132,000
831
$ 132,831
Mr. Dunn
$ 440,000
3,568
$ 443,568
Mr. Boyd
$ 155,100
768
$ 155,868
Mr. Keating
$ 150,150
1,461
$ 151,611
Mr. Brinkworth
$ 128,700
1,058
$ 129,758
(5) The amounts reported in this column represent each named executive officer’s Cash Balance Plan earnings and for Messrs. Alexander and Dunn,
SERP earnings for the year. The decline in values of pension and nonqualified deferred compensation balances for fiscal 2008 were ($150,315),
($23,157), ($29,043), ($57,881) and ($17,463) for Messrs. Alexander, Dunn, Boyd, Keating and Brinkworth, respectively. The decline in values of
pension and nonqualified deferred compensation balances for fiscal 2007 were ($1,460), ($3,348) and ($1,339) for Messrs. Alexander, Boyd and
Brinkworth, respectively. These amounts have been omitted from the table because they are negative. Mr. Stivala is not a participant in these plans.
85
(6) The amounts reported in this column consist of the following:
Type of Compensation
401(k) Match
Value of Annual Physical Examination
Value of Partnership Provided Vehicle
Tax Preparation Services
Cash Balance Plan Administrative Fees
Insurance Premiums
Severance Payments
Totals
Type of Compensation
401(k) Match
Value of Annual Physical Examination
Value of Partnership Provided Vehicle
Tax Preparation Services
Cash Balance Plan Administrative Fees
Insurance Premiums
Totals
Mr. Alexander
$ -
1,300
11,819
3,500
1,500
19,082
1,126,693
$ 1,163,894
Mr. Alexander
$ 3,450
1,500
11,395
5,000
1,500
24,081
$ 46,926
2009
Mr. Stivala
$ 14,700
1,300
11,318
N/A
N/A
14,410
N/A
$ 41,728
2008
Mr. Stivala
$ 3,450
1,500
12,647
N/A
N/A
14,992
$ 32,589
2007
Mr. Dunn
$ 14,700
N/A
12,205
3,000
1,500
16,660
N/A
$ 48,065
Mr. Dunn
$ 3,450
1,500
12,888
2,500
1,500
17,138
$ 38,976
Mr. Boyd
$ 14,700
N/A
6,205
3,000
1,500
14,406
N/A
$ 39,811
Mr. Boyd
$ 3,450
N/A
6,549
900
1,500
14,007
$ 26,406
Mr. Alexander
$ 13,500
1,200
Mr. Stivala
$ 12,485
1,200
Mr. Dunn
$ 13,500
1,200
Mr. Boyd
$ 13,500
N/A
Mr. Keating
$ 14,200
1,300
11,015
3,000
1,500
14,568
N/A
$ 45,583
Mr. Keating
$ 3,300
1,200
11,522
2,500
1,500
15,087
$ 35,109
Mr. Brinkworth
$ 13,825
N/A
10,610
3,000
1,500
14,505
N/A
$ 43,440
Mr. Brinkworth
$ 3,248
1,200
11,395
2,500
1,500
15,038
$ 34,881
Mr. Keating
$ 12,697
1,500
Mr. Brinkworth
$ 11,894
1,500
Type of Compensation
401(k) Match
Value of Annual Physical Examination
Value of Partnership Provided Vehicle
or, in Mr. Stivala’s Case, Car Allowance
Tax Preparation Services
Cash Balance Plan Administrative Fees
Insurance Premiums
Totals
11,078
2,000
1,500
23,229
$ 52,507
4,675
N/A
N/A
13,996
$ 32,356
10,198
2,000
1,500
16,481
$ 44,879
5,647
950
1,500
12,605
$ 34,202
11,522
2,000
1,500
14,597
$ 43,816
10,395
2,000
1,500
14,431
$ 41,720
Note: Column (f) was omitted from the Summary Compensation Table because the Partnership does not grant options to its employees.
Grants of Plan Based Awards Table for Fiscal 2009
The following table sets forth certain information concerning grants of awards made to each named executive
officer during the fiscal year ended September 26, 2009:
Estimated Future Payments
Under Non-Equity Incentive
Plan Awards
Estimated Future Payments
Under Equity Incentive Plan
Awards
Target
($)
(d)
N/A
$450,000
Maximum
($)
(e)
N/A
$495,000
Target
($)
(g)
N/A
Maximum
($)
(h)
N/A
$191,936
$239,920
All Other stock
Awards:
Number of
Shares of Stock
or Units
(#)
Grant Date
Fair Value of
Stock and
Option
Awards
($) (5)
(i)
N/A
(l)
N/A
4,818
$87,177
$195,000
$214,500
N/A
$425,000
N/A
$467,500
$144,156
$180,195
N/A
N/A
N/A
N/A
$314,197
$392,746
$195,000
$214,500
$144,156
$180,195
$146,250
$160,875
$108,143
$135,179
$168,750
$185,625
$124,768
$155,960
2,570
$46,504
4,818
$87,177
3,212
$58,115
Phantom
Units
Underlying
Equity
Incentive
Plan Awards
(LTIP-2)(4)
N/A
3,752
2,818
N/A
6,142
2,818
2,114
2,439
Name
(a)
Mark Alexander
Michael Stivala
Michael Dunn, Jr.
Steven Boyd
Michael Keating
Douglas. Brinkworth
Plan
Name
Grant
Date
Approval
Date
RUP (1)
Bonus(2)
LTIP-2(3)
RUP(1)
Bonus(2)
LTIP-2(3)
RUP (1)
Bonus(2)
LTIP-2(3)
RUP (1)
Bonus(2)
LTIP-2(3)
RUP (1)
Bonus(2)
LTIP-2(3)
RUP (1)
Bonus(2)
LTIP-2(3)
(b)
N/A
28 Sep 08
28 Sep 08
1 Dec 08
28 Sep 08
28 Sep 08
1 Sep 09
28 Sep 08
28 Sep 08
1 Dec 08
28 Sep 08
28 Sep 08
1 Dec 08
28 Sep 08
28 Sep 08
1 Dec 08
28 Sep 08
28 Sep 08
N/A
13Nov 08
N/A
13Nov 08
13Nov 08
13Nov 08
(1) The quantities reported on these lines represent discretionary awards under the Partnership’s 2000 Restricted Unit Plan. RUP awards vest as
follows: 25% of the award on the third anniversary of the grant date; 25% of the award on the fourth anniversary of the grant date; and 50% of
the award on the fifth anniversary of the grant date. If a recipient has held an unvested award for at least six months; is 55 years or older; and
has worked for the Partnership for at least ten years, an award held by such participant will vest six months following such participant’s
86
retirement if the participant retires prior to the conclusion of the normal vesting schedule unless the Committee exercises its discretionary
authority to alter the applicability of the plan’s retirement provisions in regard to a particular award. On September 26, 2009, Mr. Dunn and Mr.
Keating were the only named executive officers who held RUP awards and, at the same time, satisfied all three retirement eligibility criteria.
However, as a condition of Mr. Dunn’s fiscal 2008 award, the Committee requires Mr. Dunn to hold his award for three years from the grant
date before the plan’s retirement provisions become applicable. Detailed discussions of the general terms of the RUP and the facts and
circumstances considered by the Committee in authorizing the 2009 awards to the named executive officers is included in the “Compensation
Discussion and Analysis” under the subheading “2000 Restricted Unit Plan.”
(2) Amounts reported on these lines are the targeted and maximum annual cash bonus compensation potential for each named executive officer
under the annual cash bonus plan as described in the “Compensation Discussion and Analysis” under the subheading “Annual Cash Bonus
Plan.” Actual amounts earned by the named executive officers for fiscal 2009 were equal to 110% of the “Target” amounts reported on this line.
Column (c) (“Threshold $”) was omitted because the annual cash bonus plan does not provide for a minimum cash payment. Because these plan
awards were granted to, and 110% of the “Target” awards were earned by, our named executive officers during fiscal 2009, 110% of the
“Target” amounts reported under column (d) have been reported in the Summary Compensation Table above.
(3) LTIP-2 is a phantom unit plan. As discussed in the “Compensation Discussion and Analysis” above, under the subheading “2003 Long-Term
Incentive Plan,” in accordance with a verbal agreement between Mr. Alexander and the Board of Supervisors, Mr. Alexander’s award is based
upon 30% of his annual target cash bonus; however, Mr. Dunn’s award (as are the awards of all of the other named executive officers) is based
upon 52% of his annual target cash bonus. The different percentages account for the apparent differences between amounts reported for Mr.
Alexander and for Mr. Dunn.
Payments, if earned, are based on a combination of (1) the fair market value of our Common Units at the end of a three-year measurement
period, which, for purposes of the plan, is the average of the closing prices for the twenty business days preceding the conclusion of the three-
year measurement period, and (2) cash equal to the distributions that would have inured to the same quantity of outstanding Common Units
during the same three-year measurement period. The fiscal 2009 award “Target ($)” and “Maximum ($)” amounts are estimates based upon (1)
the fair market value (the average of the closing prices of our Common Units for the twenty business days preceding September 26, 2009) of our
Common Units at the end of fiscal 2009, and (2) the estimated distributions over the course of the award’s three-year measurement period.
Column (f) (“Threshold $”) was omitted because LTIP-2 does not provide for a minimum cash payment. Detailed descriptions of the plan and
the calculation of awards are included in the “Compensation Discussion and Analysis” under the subheading “2003 Long-Term Incentive Plan.”
(4) This column is frequently used when non-equity incentive plan awards are denominated in units; however, in this case, the numbers reported
represent the phantom units each named executive officer was awarded under LTIP-2 during fiscal 2009.
(5) The dollar amounts reported in this column represent the aggregate fair value of the RUP awards on the grant date, net of estimated future
distributions during the vesting period. The fair value shown may not be indicative of the value realized in the future upon vesting due to the
variability in the trading price of our Common Units.
Note: Columns (j) and (k) were omitted from the Grants of Plan Based Awards Table because the Partnership does not award options to its employees.
Outstanding Equity Awards at Fiscal Year End 2009 Table
The following table sets forth certain information concerning outstanding equity awards under our 2000
Restricted Unit Plan and phantom equity awards under our 2003 Long-Term Incentive Plan for each named
executive officer as of September 26, 2009 (no awards were granted under our 2009 Restricted Unit Plan as of
such date):
Name
(a)
Mark A. Alexander
Michael A. Stivala(1)
Michael J. Dunn, Jr. (2)
Steven C. Boyd(3)
Michael M. Keating(4)
Douglas T. Brinkworth(5)
Stock Awards
Number of
Shares or Units of
Stock That Have
Not Vested
(#)(6)
Market Value
of Shares or
Units of Stock
That Have Not
Vested
($)(7)
Equity Incentive
Plan Awards:
Number of
Unearned
Shares, Units or
Other Rights
that Have Not
Vested
(#)(8)
(g)
-
16,694
29,533
16,874
10,424
14,252
(h)
-
$ 689,212
$1,219,270
$ 696,643
$ 430,355
$ 588,394
(i)
6,741
4,689
11,036
4,511
3,761
4,296
Equity Incentive Plan
Awards: Market or
Payout Value of
Unearned Shares,
Units or Other Rights
That Have Not Vested
($)(9)
(j)
$344,206
$239,471
$563,515
$230,404
$192,047
$219,370
87
(1) Mr. Stivala’s RUP awards will vest as follows:
Vesting Date
Quantity of
Units
Oct. 1,
2009
Nov 1,
2009
Apr 25,
2010
Oct 1,
2010
Nov 1,
2010
Dec 3,
2010
Apr
25,
2011
Dec 1,
2011
Dec 3,
2011
Apr 25,
2012
Dec 1,
2012
Dec 3,
2012
Dec 1,
2013
870
900
1,374
1,738
600
568
1,374
1,205
568
2,748
1,205
1,136
2,408
(2) Despite Mr. Dunn’s having met the plan’s retirement criteria (explained under the subheading “2000 Restricted Unit Plan” in the
“Compensation Discussion and Analysis”), Mr. Dunn’s fiscal 2008 RUP award of 29,533 unvested units will not be subject to the plan’s
retirement provisions until December 3, 2010. For more information on this and the retirement provisions, refer to the subheading “2000
Restricted Unit Plan” in the “Compensation Discussion and Analysis.” If Mr. Dunn does not retire prior to the conclusion of the normal vesting
schedule of his RUP awards, his RUP awards will vest as follows:
Vesting
Date
Quantity of
Units
Dec 3,
2010
Dec 3,
2011
Dec 3,
2012
7,384
7,384
14,765
(3) Mr. Boyd’s RUP awards will vest as follows:
Vesting Date
Quantity of
Units
Nov 1,
2009
Apr 25,
2010
Nov 1,
2010
Dec 3,
2010
Apr 25,
2011
Dec 1,
2011
Dec 3,
2011
Apr 25,
2012
Dec 1,
2012
Dec 3,
2012
Dec 1,
2013
2,200
1,374
3,200
852
1,374
643
852
2,748
643
1,704
1,284
(4) Mr. Keating met the retirement eligibility criteria (explained under the subheading “2000 Restricted Unit Plan” in the “Compensation
Discussion and Analysis”) during fiscal 2008. If he does not retire prior to the conclusion of the normal vesting schedule of his RUP awards, his
RUP awards will vest as follows:
Vesting Date
Quantity of
Units
Apr 25,
2010
Dec 3,
2010
Apr 25,
2011
Dec 1,
2011
Dec 3,
2011
Apr 25,
2012
Dec 1,
2012
Dec 3,
2012
Dec 1,
2013
550
852
550
1,205
852
1,098
1,205
1,704
2,408
(5) Mr. Brinkworth’s RUP awards will vest as follows:
Vesting Date
Quantity of
Units
Oct 1,
2009
Nov 1,
2009
Apr 25,
2010
Oct 1,
2010
Nov 1,
2010
Dec 3,
2010
Apr 25,
2011
Dec 1,
2011
Dec 3,
2011
Apr 25
2012
Dec 1,
2012
Dec 3,
2012
Dec 1,
2013
870
1,525
413
1,738
1,850
852
413
803
852
823
803
1,704
1,606
(6) The figures reported in this column represent the total quantity of each of our named executive officer’s unvested RUP awards.
(7) The figures reported in this column represent the figures reported in column (g) multiplied by the average of the highest and the lowest trading
prices of our Common Units on September 25, 2009, the last trading day of fiscal 2009.
(8) The amounts reported in this column represent the quantities of phantom units that underlie the outstanding and unvested fiscal 2008 and fiscal
2009 awards under LTIP-2. Payments, if earned, will be made to participants at the end of a three-year measurement period and will be based
upon our total return to Common Unitholders in comparison to the total return provided by a predetermined peer group of eleven other
companies, all of which are publicly-traded partnerships, to their unitholders. For more information on LTIP-2, refer to the subheading “2003
Long-Term Incentive Plan” in the “Compensation Discussion and Analysis.”
(9) The amounts reported in this column represent the estimated future target payouts of the fiscal 2008 and fiscal 2009 LTIP-2 awards. These
amounts were computed by multiplying the quantities of the unvested phantom units in column (i) by the average of the closing prices of our
Common Units for the twenty business days preceding September 26, 2009 (in accordance with the plan’s valuation methodology), and by
adding to the product of that calculation the product of each year’s underlying phantom units times the sum of the distributions that are
estimated to inure to an outstanding Common Unit during each award’s three-year measurement period. Due to the variability in the trading
prices of our Common Units, as well as our performance relative to the peer group, actual payments, if any, at the end of the three-year
measurement period may differ. The following chart provides a breakdown of each year’s awards:
Fiscal 2008 Phantom Units
Value of Fiscal 2008 Phantom
Units
Estimated Distributions over
Measurement Period
Fiscal 2009 Phantom Units
Value of Fiscal 2009 Phantom
Units
Estimated Distributions over
Measurement Period
Mr. Alexander
2,989
Mr. Stivala
1,871
Mr. Dunn
4,894
Mr. Boyd
1,693
Mr. Keating
1,647
Mr. Brinkworth
1,857
$ 123,447
$ 77,273
$ 202,125
$ 69,922
$ 68,022
$ 76,695
$ 28,823
$ 18,042
$ 47,193
$ 16,326
$ 15,882
$ 17,907
3,752
2,818
6,142
2,818
2,114
2,439
$ 154,960
$ 116,385
$ 253,667
$ 116,385
$ 87,309
$ 100,732
$ 36,976
$ 27,771
$ 60,530
$ 27,771
$ 20,834
$ 24,036
Note: Columns (b), (c), (d), (e) and (f), all of which are for the reporting of option-related compensation, have been omitted from the Outstanding
Equity Awards At Fiscal Year End Table because we do not grant options to our employees.
88
Equity Vested Table for Fiscal 2009
Awards under the 2000 Restricted Unit Plan are settled in Common Units upon vesting. Awards under the
2003 Long-Term Incentive Plan, a phantom-equity plan, are settled in cash. The following two tables set forth
certain information concerning the vesting of awards under our 2000 Restricted Unit Plan and the vesting of the
fiscal 2007 award under our 2003 Long-Term Incentive Plan for each named executive officer during the fiscal
year ended September 26, 2009:
2000 Restricted Unit Plan
Unit Awards
Name
Mark A. Alexander
Michael A. Stivala
Michael J. Dunn, Jr.
Steven C. Boyd
Michael M. Keating
Douglas T. Brinkworth
Number of
Common
Units
Acquired on
Vesting
(#)
-
2,070
-
2,500
-
2,695
Value
Realized on
Vesting
($)(1)
-
$69,528
-
$84,150
-
$90,566
(1) The value realized is equal to the average of the high and low trading prices of our Common Units on the vesting date, multiplied by the number
of units that vested.
2003 Long-Term Incentive Plan –
Fiscal 2007(2) Award
Cash Awards
Name
Mark A. Alexander
Michael A. Stivala
Michael J. Dunn, Jr.
Steven C. Boyd
Michael M. Keating
Douglas T. Brinkworth
Number of
Phantom
Units
Acquired on
Vesting
(#)(3)
4,007
1,603
6,174
2,037
2,107
1,806
Value Realized on
Vesting ($)(4)
$254,479
$101,004
$389,020
$128,305
$132,761
$113,795
(2) The fiscal 2007 award’s three-year measurement period concluded on September 26, 2009.
(3)
In accordance with the formula described in the “Compensation Discussion and Analysis” under the subheading “2003 Long-Term Incentive
Plan,” these quantities were calculated at the beginning of the three-year measurement period and were, therefore, based upon each individual’s
salary and target cash bonus at that time.
(4) The value (i.e., cash payment) realized was calculated in accordance with the terms and conditions of LTIP-2. For more information, refer to the
subheading “2003 Long-Term Incentive Plan” in the “Compensation Discussion and Analysis.”
89
Pension Benefits Table for Fiscal 2009
The following table sets forth certain information concerning each plan that provides for payments or other
benefits at, following, or in connection with retirement for each named executive officer as of the end of the
fiscal year ended September 26, 2009:
Name
Mark A. Alexander
Plan Name
SERP (1)
Cash Balance Plan (2)
Number
of Years
Credited
Service
(#)
7
7
Present Value
of
Accumulated
Benefit
($)
$ 444,030
$ 216,432
Payments
During Last
Fiscal Year
($)
$ 444,030
$ -
Michael A. Stivala(3)
N/A
N/A
$ -
$ -
Michael J. Dunn, Jr.
SERP (1)
Cash Balance Plan (2)
LTIP-2 (4)
RUP(5)
Steven C. Boyd
Cash Balance Plan (2)
Michael M. Keating
Cash Balance Plan (2)
LTIP-2 (4)
RUP(5)
6
6
N/A
N/A
15
15
N/A
N/A
$ 51,610
$ 220,698
$ 563,515
N/A
$ -
$ -
$ -
$ -
$ 120,322
$ -
$ 388,163
$ 192,047
$ 430,355
$ -
$ -
$ -
Douglas T. Brinkworth
Cash Balance Plan (2
6
$ 75,716
$ -
(1) Mr. Dunn is the sole remaining SERP participant. In accordance with the terms of Mr. Alexander’s separation and consulting agreement, the
figure reported on this line is the payment he received and represents the accumulated benefit due to Mr. Alexander if he had remained in our
employ until attaining age 55. For more information on the SERP, refer to the subheading “Supplemental Executive Retirement Plan” in the
“Compensation Discussion and Analysis.”
(2) For more information on the Cash Balance Plan, refer to the subheading “Pension Plan” in the “Compensation Discussion and Analysis.”
(3) Because Mr. Stivala commenced employment with the Partnership after January 1, 2000, the date on which the Cash Balance Plan was closed to
new participants, he does not participate in the Cash Balance Plan.
(4) Currently, Mr. Dunn and Mr. Keating are the only named executive officers who meet the retirement criteria of the LTIP-2 plan document. For
such participants, upon retirement, outstanding but unvested LTIP-2 awards become fully vested. However, payouts on those awards are
deferred until the conclusion of each outstanding award’s three-year measurement period, based on the outcome of the TRU relative to the peer
group. The number reported on this line represents a projected payout of Mr. Dunn’s and Mr. Keating’s outstanding fiscal 2008 and fiscal 2009
LTIP-2 awards. Because the ultimate payout, if any, is predicated on the trading prices of the Partnership’s Common Units at the end of the
three-year measurement period, as well as where within the peer group our TRU falls, the value reported may not be indicative of the value
realized in the future upon vesting due to the variability in the trading price of our Common Units.
(5) Currently, Mr. Dunn and Mr. Keating are the only named executive officers who meet the retirement criteria of the RUP document. Despite Mr.
Dunn’s having met the plan’s retirement criteria, his fiscal 2008 award will not be subject to the plan’s retirement provisions until December 3,
2010. For more information on this and the retirement provisions, refer to the subheading “2000 Restricted Unit Plan” in the “Compensation
Discussion and Analysis.” For participants who meet the retirement criteria, upon retirement, outstanding RUP awards vest six months and
one day after retirement. The value reported in this table on behalf of Mr. Keating represents the value of 10,424 Common Units using the
average of the highest and the lowest trading prices of our Common Units on September 25, 2009.
Potential Payments Upon Termination
Potential Payments upon Termination to Named Executive Officers with Employment Agreements
Although concurrent with the beginning of fiscal 2010, Mr. Alexander’s employment agreement no longer
has force or effect and Mr. Dunn agreed to the termination of his employment agreement in exchange for a letter
of agreement and participation in the Severance Protection Plan, the following table sets forth certain information
concerning the potential payments to Mr. Alexander and Mr. Dunn under their former employment agreements,
the SERP, LTIP-2 and the RUP for the hypothetical circumstances listed in the table assuming a September 26,
2009 termination date. Ancillary tables follow this table to illustrate the payments that Mr. Alexander will
90
actually receive under his separation and consulting agreement and to illustrate potential payments to Mr. Dunn
in accordance with the letter of agreement between him and the Board of Supervisors that went into effect and
replaced his employment agreement as of the beginning of fiscal 2010.
Executive Payments and Benefits Upon Termination
Death
Disability
Mark A. Alexander
Cash Compensation(1)
Accelerated Vesting of Fiscal 2008 and 2009 LTIP-2 Awards(2)
SERP(5)
Medical Benefits
280G Tax Gross-up
409A Tax Gross-up
Total
Michael J. Dunn, Jr.
Cash Compensation(1)
Accelerated Vesting of Fiscal 2008 and 2009 LTIP-2 Awards(2)
Accelerated Vesting of Outstanding RUP Awards(6)
SERP
Medical Benefits
280G Tax Gross-up
409A Tax Gross-up
$ -0-(3)
N/A
227,800
N/A
N/A
N/A
$ 227,800
$ -0-(3)
N/A
N/A
30,300
N/A
N/A
N/A
Total
$ 30,300
$ -0-(4)
N/A
477,000
N/A
N/A
N/A
$ 477,000
$ -0-(4)
N/A
1,219,270
53,500
N/A
N/A
N/A
$ 1,272,770
Involuntary
Termination
Without Cause
by the
Partnership or
by the
Executive for
Good Reason
without a
Change of
Control Event
Involuntary
Termination
Without Cause
by the
Partnership or
by the
Executive for
Good Reason
with a Change
of Control
Event
$ 1,350,000
N/A
N/A
26,307
N/A
N/A
$ 1,376,307
$ 950,000
N/A
N/A
53,500
23,384
N/A
N/A
$ 1,026,884
$ 2,835,000
386,974
662,700
26,307
N/A
N/A
$ 3,910,981
$ 1,995,000
633,534
1,219,270
51,800
23, 384
N/A
N/A
$ 3,922,988
(1) For additional information on the cash compensation that would have been payable to Mr. Alexander and Mr. Dunn under the provisions of their
respective former employment agreements if any of the four hypothetical events had occurred at the conclusion of fiscal 2009, refer to the
subheading “Employment Agreements” in the “Compensation Discussion and Analysis.”
(2)
In the event of a change of control, all LTIP-2 awards will vest immediately regardless of whether termination immediately follows. If a change
of control event occurs, the calculation of the LTIP-2 payment will be made as if our total return to our Common Unitholders in the top quartile
of the peer group. For more information, refer to the subheading “2003 Long-Term Incentive Plan” in the “Compensation Discussion and
Analysis.” In the event of death, the inability to continue employment due to permanent disability, or a termination without cause or a good
reason resignation unconnected to a change of control event, awards will vest in accordance with the normal vesting schedule and will be subject
to the same requirements and risks as awards held by individuals still employed by the Partnership and will be subject to the same risks as
awards held by all other participants.
(3) Under their former employment agreements, in the event of death, Mr. Alexander’s and Mr. Dunn’s estates would have been entitled to a
payment equal to the decedent’s earned but unpaid salary and pro-rata cash bonus at the time of death.
(4) Under their former employment agreements, in the event of disability, each is entitled to a payment equal to his earned but unpaid salary and
pro-rata cash bonus.
(5) Because Mr. Alexander had not attained age 55 on September 26, 2009, had it not been for the terms of his separation and consulting agreement,
if any of the above hypothetical events had occurred on that date, without regard to the terms of his separation and consulting agreement that
superseded the normative provisions of the SERP, only death, disability or a change of control would have given rise to a SERP-related payment.
Change of control related payments are due to Mr. Alexander and Mr. Dunn within 30 days of the change of control event, regardless of whether
termination or resignation follows the event. In the event of death, Mr. Alexander’s estate would have received a lump sum payment of
$227,800. In the event of disability, if Mr. Alexander remained disabled until age 55, he would be eligible for a lump sum payment, at that time,
of $960,300. The figure $477,000 reported in the table represents the present value of the hypothetical future payment.
(6) The RUP document makes no provisions for the vesting of awards held by recipients who die prior to the completion of the vesting schedule. If
a recipient of a RUP award becomes permanently disabled, only those awards that have been held for at least one year on the date that the
employee’s employment is terminated as a result of his or her permanent disability will immediately vest; all awards held by the recipient for less
than one year will be forfeited by the recipient. Because Mr. Dunn’s fiscal 2008 RUP award of 29,533 units was granted more than one year
prior to September 26, 2009, if he had become permanently disabled on September 26, 2009, his fiscal 2008 RUP award would have vested.
Under circumstances unrelated to a change of control, if a RUP award recipient’s employment is terminated without cause or he or she resigns
for good reason, any RUP awards held by such recipient will be forfeited. In the event of a change of control, as defined in the RUP document,
all unvested RUP awards will vest immediately on the date the change of control is consummated, regardless of the holding period and
regardless of whether the recipient’s employment is terminated.
91
Actual Payments to Mr. Alexander under His Separation and Consulting Agreement
The following table provides information concerning the Partnership’s separation and consulting agreement
with Mr. Alexander who was succeeded as our Chief Executive Officer by Mr. Dunn on September 27, 2009:
Executive Payments and Benefits Upon Termination
Cash Compensation(1)
Annual Cash Bonus(2)
Payment of Remaining LTIP-2 Awards(3)
Vehicle(4)
Medical Benefits & Supplemental Life Insurance Coverage(5)
Income Tax Preparation Services for Three Years(6)
SERP Payment(7)
280(G)Tax Gross-up
409(A)Tax Gross-up
Total
Payments
Received for
Orderly Plan
of Succession:
Separation
and
Consulting
Agreement
$ 1,000,000
495,000
344,206
58,947
57,246
10,500
444,030
N/A
N/A
$ 2,409,929
(1) The amount reported on this line represents the aggregate consulting fee that Mr. Alexander will receive for the three-year consulting period
commencing on September 27, 2009. During the consulting period, Mr. Alexander will provide transitional assistance and strategic advice to
the Board of Supervisors and to Mr. Dunn. This amount will be paid in bi-weekly installments over the course of the three-year consulting
period and has been reported in the column titled “All Other Compensation ($)” in the Summary Compensation Table above.
(2) The amount reported on this line represents Mr. Alexander’s full annual cash bonus, without pro-ration, for fiscal 2009 and has been reported in
the column titled “Non-Equity Incentive Plan Compensation ($)” in the Summary Compensation Table above.
(3) The amount reported on this line represents the estimated payments of Mr. Alexander’s two remaining, unvested LTIP-2 awards (i.e., the fiscal
2008 and 2009 awards). Mr. Alexander’s fiscal 2008 and 2009 awards will be paid, if earned, in accordance with the provisions of the LTIP-2
plan document. Because Mr. Alexander, the service provider, has no additional services to perform in order to receive any cash payments for
these awards, all remaining, unamortized compensation expense associated with these awards was recognized during fiscal 2009 and has been
reported in the column titled “Unit Awards ($)” in the Summary Compensation Table above.
(4) The amount reported on this line represents the imputed fair market value for use of a vehicle provided by the Partnership and the estimated cost
of fuel for the vehicle during the three-year consulting period and has been reported in the column titled “All Other Compensation ($)” in the
Summary Compensation Table above.
(5) The amount reported on this line represents the estimated cost of health insurance premiums and supplemental life insurance coverage during
the three-year consulting period and has been reported in the column titled “All Other Compensation ($)” in the Summary Compensation Table
above.
(6) The amount reported on this line represents the estimated cost to reimburse Mr. Alexander for income tax preparation services for three years
and has been reported in the column titled “All Other Compensation ($)” in the Summary Compensation Table above.
(7) The amount reported on this line represents the lump-sum payment under the SERP equal to what said payment would have been if Mr.
Alexander had attained age 55 on September 26, 2009. In accordance with the provisions of Mr. Alexander’s separation and consulting
agreement, this amount was paid within thirty days of the conclusion of fiscal 2009. All above market interest credits relative to this payment
have been reported in the column titled “Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)” in the Summary
Compensation Table above.
92
Potential Payments upon Termination to Mr. Dunn under his Letter of Agreement
The following table sets forth certain information containing potential payments to Mr. Dunn under the letter
of agreement between him and the Partnership and in accordance with the provisions of the Severance Protection
Plan, the RUP and LTIP-2 for the circumstances listed in the table assuming a September 26, 2009 termination
date:
Involuntary
Termination
Without Cause
by the
Partnership or
by the
Executive for
Good Reason
without a
Change of
Control Event
Involuntary
Termination
Without Cause
by the
Partnership or
by the Executive
for Good
Reason with a
Change of
Control Event
Terminati
on as a
Result of
Retirement
or an
Agreed-
Upon
Succession
Plan in
Accordanc
e with the
Letter of
Agreement
between
Mr. Dunn
and the
Board
Executive Payments and Benefits Upon Termination
Death
Disability
Michael J. Dunn
Cash Compensation
Accelerated Vesting of Fiscal 2008 and 2009 LTIP-2
Awards(6)
Accelerated Vesting of Outstanding RUP Awards(7)
SERP(8)
Medical Benefits(3)
280G Tax Gross-up
409A Tax Gross-up
Total
$ -0-(1)
$ -0-(2)
$ 475,000(3)
$ 1,425,000(4)
$ -0-(5)
N/A
N/A
30,300
N/A
N/A
N/A
$ 30,300
N/A
1,219,270
53,500
N/A
N/A
N/A
$ 1,272,770
N/A
N/A
53,500
N/A
11,692
N/A
$ 540,192
633,534
1,219,270
51,800
N/A
N/A
N/A
$ 3,329,604
N/A
N/A
N/A
N/A
N/A
N/A
$ N/A
(1)
In the event of death, Mr. Dunn’s estate would be entitled to a payment equal to his earned but unpaid salary and pro-rata cash bonus.
(2)
In the event of disability, Mr. Dunn would be entitled to a payment equal to his earned but unpaid salary and pro-rata cash bonus.
(3) Any severance benefits, unrelated to a change of control event, payable to Mr. Dunn would be determined by the Committee on a case-by-case
basis in accordance with prior treatment of other similarly situated executives and may, as a result, differ from this hypothetical presentation.
For purposes of this table, we have assumed that Mr. Dunn would, upon termination of employment without cause or for resignation for good
reason, receive accrued salary and benefits through the date of termination plus one times annual salary, paid in the form of salary continuation,
and continued participation, at active employee rates, in the Partnership’s health insurance plans for one year.
(4)
(5)
(6)
In the event of a change of control followed by a termination without cause or by a resignation with good reason, Mr. Dunn, and each of the
other named executive officers without employment agreements or letters of understanding, will receive 78 weeks of base pay plus a sum equal
to their annual target cash bonus divided by 52 and multiplied by 78 in accordance with the terms of the Severance Protection Plan. For more
information on the Severance Protection Plan, refer to the subheading “Change of Control” in the “Compensation Discussion and Analysis.”
In accordance with the terms of Mr. Dunn’s letter of agreement, if he retires prior to the last day of fiscal 2012, the assumptions contained in
footnote 3 (above) will govern. If, in accordance with an agreed upon succession plan, he were to retire on the last day of fiscal 2012 or anytime
thereafter, he will receive a lump-sum cash payment equal to two years of his base salary at that time.
In the event of a change of control, all LTIP-2 awards will vest immediately regardless of whether termination immediately follows. If a change
of control event occurs, the calculation of the LTIP-2 payment will be made as if our total return to Common Unitholders was in the top quartile
of the peer group. For more information, refer to the subheading “2003 Long-Term Incentive Plan” in the “Compensation Discussion and
Analysis.” In the event of death, the inability to continue employment due to permanent disability, or a termination without cause or a good
reason resignation unconnected to a change of control event, awards will vest in accordance with the normal vesting schedule and will be subject
to the same requirements as awards held by individuals still employed by the Partnership and will be subject to the same risks as awards held by
all other participants.
(7) The RUP document makes no provisions for the vesting of awards held by recipients who die prior to the completion of the vesting schedule. If
a recipient of a RUP award becomes permanently disabled, only those awards that have been held for at least one year on the date that the
employee’s employment is terminated as a result of his or her permanent disability will immediately vest; all awards held by the recipient for less
than one year will be forfeited by the recipient. Because Mr. Dunn’s fiscal 2008 RUP award of 29,533 units was granted more than one year
93
prior to September 26, 2009, if he had become permanently disabled on September 26, 2009, his fiscal 2008 RUP award would have vested;
however, because his fiscal 2009 RUP award of 25,000 units was granted less than one year prior to September 26, 2009, his fiscal 2009 RUP
award would have been forfeited.
In the event of death, the inability to continue employment due to permanent disability, or a termination without cause or a good reason
resignation unconnected to a change of control event, awards will vest in accordance with the normal vesting schedule and will be subject to the
same requirements as awards held by individuals still employed by the Partnership and will be subject to the same risks as awards held by all
other participants.
(8) Because Mr. Dunn attained age 55 prior to September 26, 2009, if any of the above hypothetical events had occurred on that date, each event
would give rise to a SERP-related payment.
Potential Payments upon Termination to Named Executive Officers without Employment Agreements
The following table sets forth certain information containing potential payments to the three named executive
officers without employment agreements in accordance with the provisions of the Severance Protection Plan, the
RUP and LTIP-2 for the circumstances listed in the table assuming a September 26, 2009 termination date:
Executive Payments and Benefits Upon Termination
Death
Disability
Involuntary
Termination
Without Cause
by the
Partnership or
by the
Executive for
Good Reason
without a
Change of
Control Event
Involuntary
Termination
Without Cause
by the
Partnership or
by the
Executive for
Good Reason
with a Change
of Control
Event
Michael A. Stivala
Cash Compensation(1) (2) (3) (4)
Accelerated Vesting of Fiscal 2008 and 2009 LTIP-2 Awards(5)
Accelerated Vesting of Outstanding RUP Awards(6)
Medical Benefits(3)
280G Tax Gross-up
409A Tax Gross-up
Total
Steven C. Boyd
Cash Compensation(1) (2) (3) (4)
Accelerated Vesting of Fiscal 2008 and 2009 LTIP-2 Awards(5)
Accelerated Vesting of Outstanding RUP Awards(6)
Medical Benefits(3)
280G Tax Gross-up
409A Tax Gross-up
Total
Michael M. Keating
Cash Compensation(1) (2) (3) (4)
Accelerated Vesting of Fiscal 2008 and 2009 LTIP-2 Awards(5)
Accelerated Vesting of Outstanding RUP Awards(6)
Medical Benefits(3)
280G Tax Gross-up
409A Tax Gross-up
Total
Douglas T. Brinkworth
Cash Compensation(1) (2) (3) (4)
Accelerated Vesting of Fiscal 2008 and 2009 LTIP-2 Awards(5)
Accelerated Vesting of Outstanding RUP Awards(6)
Medical Benefits(3)
280G Tax Gross-up
409A Tax Gross-up
Total
$ -0-
N/A
490,301
N/A
N/A
N/A
$ 490,301
$ -0-
N/A
590,541
N/A
N/A
N/A
$ 590,541
$ 275,000
N/A
N/A
11,692
N/A
N/A
$ 286,692
$ 260,000
N/A
N/A
11,422
N/A
N/A
$ 271,422
$ 721,875
268,374
689,212
N/A
N/A
N/A
$ 1,679,461
$ 682,500
257,774
696,643
N/A
N/A
N/A
$ 1,636,917
$ -0-
N/A
231,444
N/A
N/A
N/A
$ 231,444
$ 260,000
N/A
N/A
11,692
N/A
N/A
$ 271,692
$ 663,000
215,824
430,355
N/A
N/A
N/A
$ 1,309,179
$ -0-
N/A
455,786
N/A
N/A
N/A
$ 455.786
$ 245,000
N/A
N/A
11,692
N/A
N/A
$ 256,692
$ 643,125
246,432
588,394
N/A
N/A
N/A
$ 1,477,951
$ -0-
N/A
N/A
N/A
N/A
N/A
$ 0
$ -0-
N/A
N/A
N/A
N/A
N/A
$ 0
$ -0_
N/A
N/A
N/A
N/A
N/A
$ 0
$ -0_
N/A
N/A
N/A
N/A
N/A
$ 0
94
(1)
In the event of death, the named executive officer’s estate is entitled to a payment equal to the decedent’s earned but unpaid salary and pro-rata
cash bonus.
(2)
In the event of disability, the named executive officer is entitled to a payment equal to his earned but unpaid salary and pro-rata cash bonus.
(3) Any severance benefits, unrelated to a change of control event, payable to these officers would be determined by the Committee on a case-by-
case basis in accordance with prior treatment of other similarly situated executives and may, as a result, differ from this hypothetical
presentation. For purposes of this table, we have assumed that each of these named executive officers would, upon termination of employment
without cause or for resignation for good reason, receive accrued salary and benefits through the date of termination plus one times annual
salary, paid in the form of salary continuation, and continued participation, at active employee rates, in the Partnership’s health insurance plans
for one year.
(4)
(5)
In the event of a change of control followed by a termination without cause or by a resignation with good reason, each of the named executive
officers without employment agreements will receive 78 weeks of base pay plus a sum equal to their annual target cash bonus divided by 52 and
multiplied by 78 in accordance with the terms of the Severance Protection Plan. For more information on the Severance Protection Plan, refer to
the subheading “Change of Control” in the “Compensation Discussion and Analysis.”
In the event of a change of control, all LTIP-2 awards will vest immediately regardless of whether termination immediately follows. If a change
of control event occurs, the calculation of the LTIP-2 payment will be made as if our total return to Common Unitholders was higher than that
provided by any of the other members of the peer group to their unitholders. For more information, refer to the subheading “2003 Long-Term
Incentive Plan” in the “Compensation Discussion and Analysis.”
In the event of death, the inability to continue employment due to permanent disability, or a termination without cause or a good reason
resignation unconnected to a change of control event, awards will vest in accordance with the normal vesting schedule and will be subject to the
same requirements as awards held by individuals still employed by the Partnership and will be subject to the same risks as awards held by all
other participants.
(6) The RUP document makes no provisions for the vesting of awards held by recipients who die prior to the completion of the vesting schedule. If
a recipient of a RUP award becomes permanently disabled, only those awards that have been held for at least one year on the date that the
employee’s employment is terminated as a result of his or her permanent disability will immediately vest; all awards held by the recipient for less
than one year will be forfeited by the recipient. Because Mr. Stivala, Mr. Boyd, Mr. Keating and Mr. Brinkworth each received a RUP award
during fiscal 2009, if any or all of the three had become permanently disabled on September 26, 2009, the following quantities of unvested
restricted units would have vested: Stivala, 11,876; Boyd, 14,304; Keating, 5,606; Brinkworth, 11,040 and the following quantities would have
been forfeited: Stivala, 4,818; Boyd, 2,570; Keating, 4,818; Brinkworth, 3,212.
Under circumstances unrelated to a change of control, if a RUP award recipient’s employment is terminated without cause or he or she resigns
for good reason, any RUP awards held by such recipient will be forfeited.
In the event of a change of control, as defined in the RUP document, all unvested RUP awards will vest immediately on the date the change of
control is consummated, regardless of the holding period and regardless of whether the recipient’s employment is terminated.
95
SUPERVISORS’ COMPENSATION
The following table sets forth the compensation of the non-employee members of the Board of Supervisors
of the Partnership during fiscal 2009.
Supervisor
John D. Collins
Harold R. Logan, Jr.
Dudley C. Mecum
John Hoyt Stookey
Jane Swift
Fees Earned
or Paid in
Cash
($) (1)
Unit Awards
($) (2)
Total
($)
$ 75,000
100,000
75,000
75,000
75,000
$ 49,861
-
-
-
49,861
$ 124,861
100,000
75,000
75,000
124,861
(1)
Includes amounts earned for fiscal 2009, including quarterly retainer installments for the fourth quarter of 2009 that were paid in October 2009.
Does not include amounts paid in fiscal 2009 for fiscal 2008 quarterly retainer installments.
(2) Represents the dollar amount charged to earnings for financial statement reporting purposes during fiscal 2009 for restricted unit awards of
5,496 awarded to both Mr. Collins and Ms. Swift on April 25, 2007. All awards were made in accordance with the provisions of our 2000
Restricted Unit Plan and vest accordingly. The average of the high and low sales price, discounted for projected distributions during the vesting
period, was used to calculate the value of the restricted unit awards for purposes of amortizing compensation expense. Because Messrs. Logan,
Mecum and Stookey have satisfied the plan’s retirement provisions, all expense for their unvested awards was previously recognized. As of
September 26, 2009, each non-employee member of the Board of Supervisors held the following quantities of unvested restricted unit awards:
Mr. Collins, 5,496 units; Mr. Logan, 7,250 units; Mr. Mecum, 7,250 units; Mr. Stookey, 7,250 units; and Ms. Swift, 5,496 units.
Note: The columns for reporting option awards, non-equity incentive plan compensation, changes in pension value and non-qualified deferred
compensation plan earnings and all other forms of compensation were omitted from the Supervisor’s Compensation Table because the Partnership does not
provide these forms of compensation to its non-employee supervisors.
Fees and Benefit Plans for Non-Employee Supervisors
Annual Cash Retainer Fees. As the Chairman of the Board of Supervisors, Mr. Logan receives an annual
retainer of $100,000, payable in quarterly installments of $25,000 each. Each of the other non-employee
Supervisors receives an annual cash retainer of $75,000, payable in quarterly installments of $18,750 each.
Meeting Fees. The members of our Board of Supervisors receive no additional remuneration for attendance
at regularly scheduled meetings of the Board or its Committees, other than reimbursement of reasonable
expenses incurred in connection with such attendance.
Restricted Unit Plan. Each non-employee Supervisor participates in the 2000 and 2009 Restricted Unit
Plans. All awards vest in accordance with the provisions of the plan document (see “Compensation Discussion
and Analysis” sections titled “2000 Restricted Unit Plan” and “2009 Restricted Unit Plan” for a description of
the vesting schedule). Upon vesting, all awards are settled by issuing Common Units. During fiscal 2004,
Messrs. Logan, Mecum and Stookey were granted unvested restricted unit plan awards of 8,500 units each;
during fiscal 2007, each of them received an additional unvested award of 3,000 units. Upon commencement of
their terms as supervisors in fiscal 2007, Mr. Collins and Ms. Swift each received an award of 5,496 units.
Additional Supervisor Compensation. Non-employee Supervisors receive no other forms of remuneration
from us. The only perquisite provided to the members of the Board of Supervisors is the ability to purchase
propane at the same discounted rate that we offer propane to our employees, the value of which was less than
$10,000 in fiscal 2009 for each Supervisor.
Compensation Committee Interlocks and Insider Participation. None.
96
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED UNITHOLDER MATTERS
The following table sets forth certain information as of November 23, 2009 regarding the beneficial
ownership of Common Units by each member of the Board of Supervisors, each executive officer named in the
Summary Compensation Table in Item 11 of this Annual Report, and all members of the Board of Supervisors
and executive officers as a group. Based upon filings under Section 13(d) or (g) under the Exchange Act, the
Partnership does not know of any person or group who beneficially owns more than 5% of the outstanding
Common Units. Except as set forth in the notes to the table, each individual or entity has sole voting and
investment power over the Common Units reported.
Name of Beneficial Owner
Mark A. Alexander
Michael J. Dunn, Jr. (a)
Michael A. Stivala (b)
Steven C. Boyd (c)
Michael M. Keating (d)
Douglas T. Brinkworth (e)
John Hoyt Stookey (f)
Harold R. Logan, Jr.(f)
Dudley C. Mecum (f)
John D. Collins (g)
Jane Swift (g)
All Members of the Board
of Supervisors and Executive
Officers (including former CEO,
Mark Alexander)
as a Group (17 persons) (h)
Amount and Nature of
Beneficial Ownership (1)
1,298,912
208,947
10,732
31,933
98,500
25,395
18,322
17,044
14,134
12,450
-0-
Percent
of Class
3.7%
*
*
*
*
*
*
*
*
*
*
1,831,336
5.2%
(1) With the exception of the 784 units held by the General Partner (see (a) below), there is a possibility that any
of the above listed units could be pledged as security.
* Less than 1%.
(a) Includes 784 Common Units held by the General Partner, of which Mr. Dunn is the sole member. Excludes
29,533 unvested restricted units, none of which will vest in the 60-day period following November 23, 2009.
(b) Excludes 14,924 unvested restricted units, none of which will vest in the 60-day period following November
23, 2009.
(c) Excludes 14,674 unvested restricted units, none of which will vest in the 60-day period following November
23, 2009.
(d) Excludes 10,424 unvested restricted units, none of which will vest in the 60-day period following November
23, 2009.
(e) Excludes 11,857 unvested restricted units, none of which will vest in the 60-day period following November
23, 2009.
97
(f) Excludes 3,000 unvested restricted units, none of which will vest in the 60-day period following November
23, 2009.
(g) Excludes 5,496 unvested restricted units, none of which will vest in the 60-day period following November
23, 2009.
(h) Inclusive of the units referred to in footnotes (a), (b), (c), (d), (e), (f) and (g) above, the reported number of
units excludes 157,110 unvested restricted units, none of which will vest in the 60 day period following
November 23, 2009, owned by certain executive officers, whose restricted units vest on the same basis as
described in footnotes (b), (c), (d), (e), (f) and (g) above.
Securities Authorized for Issuance Under the Restricted Unit Plans
The following table sets forth certain information, as of September 26, 2009, with respect to the
Partnership’s Restricted Unit Plans, under which restricted units of the Partnership, as described in the Notes to
the Consolidated Financial Statements included in this Annual Report, are authorized for issuance.
Number of Common
Units to be issued upon
vesting of restricted
units
(a)
415,295 (2)
--
415,295
Weighted-average grant
date fair value per
restricted unit
(b)
$28.89
--
$28.89
Number of restricted units
remaining available for
future issuance under the
Restricted Unit Plans (excluding
securities reflected in
column (a))
(c)
1,249,457
--
1,249,457
Plan
Category
Equity compensation plans approved by security holders (1)
Equity compensation plans not approved by security holders
Total
(1) Relates to the Restricted Unit Plans.
(2) Represents number of restricted units that, as of September 26, 2009, had been granted under the 2000
Restricted Unit Plan but had not yet vested. No restricted units have yet been granted under the 2009 Restricted
Unit Plan.
98
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR
INDEPENDENCE
Related Person Transactions
None.
Supervisor Independence
The Corporate Governance Guidelines and Principles adopted by the Board of Supervisors provide that a
Supervisor is deemed to be lacking a material relationship to the Partnership and is therefore independent of
management if the following criteria are satisfied:
1. Within the past three years, the Supervisor:
a. has not been employed by the Partnership and has not received more than $100,000 per year in direct
compensation from the Partnership, other than Supervisor and committee fees and pension or other forms
of deferred compensation for prior service;
b. has not provided significant advisory or consultancy services to the Partnership, and has not been
affiliated with a company or a firm that has provided such services to the Partnership in return for
aggregate payments during any of the last three fiscal years of the Partnership in excess of the greater of
2% of the other company’s consolidated gross revenues or $1 million;
c. has not been a significant customer or supplier of the Partnership and has not been affiliated with a
company or firm that has been a customer or supplier of the Partnership and has either made to the
Partnership or received from the Partnership payments during any of the last three fiscal years of the
Partnership in excess of the greater of 2% of the other company’s consolidated gross revenues or $1
million;
d. has not been employed by or affiliated with an internal or external auditor that within the past three years
provided services to the Partnership; and
e. has not been employed by another company where any of the Partnership’s current executives serve on
that company’s compensation committee;
2. The Supervisor is not a spouse, parent, sibling, child, mother- or father-in-law, son- or daughter-in-law or
brother- or sister-in-law of a person having a relationship described in 1. above nor shares a residence with
such person;
3. The Supervisor is not affiliated with a tax-exempt entity that within the past 12 months received significant
contributions from the Partnership (contributions of the greater of 2% of the entity’s consolidated gross
revenues or $1 million are considered significant); and
4. The Supervisor does not have any other relationships with the Partnership or with members of senior
management of the Partnership that the Board determines to be material.
99
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The following table sets forth the aggregate fees for services related to fiscal years 2009 and 2008 provided
by PricewaterhouseCoopers LLP, our independent registered public accounting firm.
Audit Fees (a)
Audit-Related Fees (b)
Tax Fees (c)
All Other Fees (d)
Fiscal
2009
Fiscal
2008
$
2,265,000
-
840,030
1,605
$
2,325,000
84,000
722,000
1,605
(a) Audit Fees consist of professional services rendered for the integrated audit of our annual consolidated
financial statements and our internal control over financial reporting, including reviews of our quarterly
financial statements, as well as the issuance of consents in connection with other filings made with the SEC.
(b) Audit-Related Fees consist of professional services rendered in connection with acquisition-related due
diligence and consultations concerning financial accounting and reporting standards.
(c) Tax Fees consist of fees for professional services related to tax reporting, tax compliance and transaction
services assistance.
(d) All Other Fees represent fees for the purchase of a license to an accounting research software tool.
The Audit Committee of the Board of Supervisors has adopted a formal policy concerning the approval of
audit and non-audit services to be provided by the independent registered public accounting firm,
PricewaterhouseCoopers LLP. The policy requires that all services PricewaterhouseCoopers LLP may provide to
us, including audit services and permitted audit-related and non-audit services, be pre-approved by the Audit
Committee. The Audit Committee pre-approved all audit and non-audit services provided by
PricewaterhouseCoopers LLP during fiscal 2009 and fiscal 2008.
100
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a) The following documents are filed as part of this Annual Report:
1. Financial Statements
See “Index to Financial Statements” set forth on page F-1.
2. Financial Statement Schedule
See “Index to Financial Statement Schedule” set forth on page S-1.
3. Exhibits
See “Index to Exhibits” set forth on page E-1.
101
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly
caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
SIGNATURES
Date: November 25, 2009
SUBURBAN PROPANE PARTNERS, L.P.
By: /s/ MICHAEL J. DUNN, JR.
Michael J. Dunn, Jr.
President, Chief Executive Officer and
Supervisor
Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report has been signed below by
the following persons on behalf of the Registrant and in the capacities and on the dates indicated:
Signature
Title
Date
By: /s/ MICHAEL J. DUNN, JR
(Michael J. Dunn, Jr.)
President, Chief Executive
Officer and Supervisor
November 25, 2009
By: /s/ HAROLD R. LOGAN, JR.
Chairman and Supervisor
November 25, 2009
(Harold R. Logan, Jr.)
By: /s/ JOHN HOYT STOOKEY
Supervisor
November 25, 2009
(John Hoyt Stookey)
By: /s/ DUDLEY C. MECUM
(Dudley C. Mecum)
By: /s/ JOHN D. COLLINS
(John D. Collins)
By: /s/ JANE SWIFT
(Jane Swift)
Supervisor
Supervisor
Supervisor
November 25, 2009
November 25, 2009
November 25, 2009
By: /s/ MICHAEL A. STIVALA
Chief Financial Officer
November 25, 2009
(Michael A. Stivala)
By /s/ MICHAEL A. KUGLIN
Controller and Chief Accounting Officer November 25, 2009
(Michael A. Kuglin)
102
The exhibits listed on this Exhibit Index are filed as part of this Annual Report. Exhibits required to be filed by
Item 601 of Regulation S-K, which are not listed below, are not applicable.
INDEX TO EXHIBITS
Exhibit
Number
2.1
3.1
3.2
3.3
3.4
4.1
4.2
4.3
4.4
10.1
Description
Exchange Agreement dated as of July 27, 2006 by and among the Partnership, the Operating
Partnership and the General Partner. (Incorporated by reference to Exhibit 10.1 to the
Partnership’s Current Report on Form 8-K filed July 28, 2006).
Third Amended and Restated Agreement of Limited Partnership of the Partnership dated as of
October 19, 2006, as amended as of July 31, 2007. (Incorporated by reference to Exhibit 3.1 to
the Partnership’s Current Report on Form 8-K filed August 2, 2007).
Third Amended and Restated Agreement of Limited Partnership of the Operating
Partnership dated as of October 19, 2006, as amended as of June 24, 2009. (Incorporated by
reference to Exhibit 10.2 to the Partnership’s Current Report on Form 8-K filed June 30, 2009).
Amended and Restated Certificate of Limited Partnership of Suburban Propane Partners, L.P.
dated May 26, 1999 (Incorporated by reference to Exhibit 3.2 to the Partnership’s Quarterly
Report on Form 10-Q filed August 6, 2009).
Amended and Restated Certificate of Limited Partnership of Suburban Partners, L.P. dated
May 26, 1999 (Incorporated by reference to Exhibit 3.3 to the Partnership’s Quarterly Report
on Form 10-Q filed August 6, 2009).
Description of Common Units of the Partnership. (Incorporated by reference to Exhibit 4.1 to
the Partnership’s Current Report on Form 8-K filed October 19, 2006).
Indenture, dated as of December 23, 2003, between Suburban Propane Partners, L.P.,
Suburban Energy Finance Corp. and The Bank of New York, as Trustee (including Form of
Senior Global Exchange Note). (Incorporated by reference to Exhibit 10.28 to the
Partnership’s Quarterly Report on Form 10-Q for the fiscal quarter ended December 27,
2003).
Exchange and Registration Rights Agreement, dated December 23, 2003 among Suburban
Propane Partners, L.P., Suburban Energy Finance Corp., Wachovia Capital Markets, LLC
and Goldman, Sachs & Co. (Incorporated by reference to Exhibit 4.1 to the Partnership’s
Registration Statement on Form S-4 dated December 19, 2003).
Exchange and Registration Rights Agreement, dated March 31, 2005 among Suburban
Propane Partners, L.P., Suburban Energy Finance Corp., Wachovia Capital Markets, LLC
and Goldman, Sachs & Co. (Incorporated by reference to Exhibit 4.1 to the Partnership’s
Current Report on Form 8-K filed April 1, 2005).
Agreement between Mark A. Alexander and the Partnership, dated April 22, 2009.
(Incorporated by reference to Exhibit 10.1 to the Partnership’s Quarterly Report on Form 10-
Q filed August 6, 2009).
E-1
10.5
10.6
10.7
10.8
10.9
10.10
10.11
10.12
10.13
10.14
10.15
21.1
23.1
31.1
31.2
Agreement between Michael J. Dunn, Jr. and the Partnership, effective as of September 27,
2009. (Incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on
Form 8-K filed November 10, 2009).
Suburban Propane Partners, L.P. 2000 Restricted Unit Plan, as amended and restated effective
October 17, 2006 and as further amended on July 31, 2007, October 31, 2007, January 24,
2008, January 20, 2009 and November 10, 2009. (Filed herewith).
Suburban Propane Partners, L.P. 2009 Restricted Unit Plan, effective August 1, 2009.
(Incorporated by reference to Exhibit 99.1 to the Partnership’s Registration Statement on Form
S-8 filed on July 24, 2009).
Suburban Propane, L.P. Severance Protection Plan, as amended on January 24, 2008,
January 20, 2009 and November 10, 2009. (Filed herewith).
Suburban Propane L.P. 2003 Long Term Incentive Plan, as amended on October 17, 2006
and as further amended on July 31, 2007, October 31, 2007, January 24, 2008 and January
20, 2009. (Incorporated by reference to Exhibit 10.3 to the Partnership’s Quarterly Report
on Form 10-Q for the fiscal quarter ended December 27, 2008).
Amended and Restated Supplemental Executive Retirement Plan of the Partnership (effective
as of January 1, 1998). (Incorporated by reference to Exhibit 10.23 to the Partnership’s Annual
Report on Form 10-K for the fiscal year ended September 29, 2001).
Amended and Restated Retirement Savings and Investment Plan of Suburban Propane effective
as of January 1, 1998). (Incorporated by reference to Exhibit 10.24 to the Partnership’s Annual
Report on Form 10-K for the fiscal year ended September 29, 2001).
Amendment No. 1 to the Retirement Savings and Investment Plan of Suburban Propane
(effective January 1, 2002). (Incorporated by reference to Exhibit 10.25 to the Partnership’s
Annual Report on Form 10-K for the fiscal year ended September 28, 2002).
Credit Agreement dated June 26, 2009. (Incorporated by reference to Exhibit 10.1 to the
Partnership’s Current Report on Form 8-K filed on June 30, 2009).
Non-Competition Agreement, dated September 17, 2007, between Suburban Propane, L.P.
and Plains LPG Services, L.P. (Incorporated by reference to Exhibit 10.2 to the Partnership’s
Current Report on Form 8-K filed September 20, 2007).
Propane Storage Agreement, dated September 17, 2007, between Suburban Propane, L.P.
and Plains LPG Services, L.P. (Incorporated by reference to Exhibit 10.3 to the Partnership’s
Current Report on Form 8-K filed September 20, 2007).
Subsidiaries of Suburban Propane Partners, L.P. (Filed herewith).
Consent of PricewaterhouseCoopers LLP. (Filed herewith).
Certification of the President and Chief Executive Officer Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002. (Filed herewith).
Certification of the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002. (Filed herewith).
E-2
32.1
32.2
Certification of the President and Chief Executive Officer Pursuant to 18 U.S.C. Section
1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (Filed
herewith).
Certification of the Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (Filed herewith).
99.1
Five-Year Performance Graph (Filed herewith).
E-3
INDEX TO FINANCIAL STATEMENTS
SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES
Page
Report of Independent Registered Public Accounting Firm.......................................................................…... F-2
Consolidated Balance Sheets –
As of September 26, 2009 and September 27, 2008......................................................................................... F-3
Consolidated Statements of Operations –
Years Ended September 26, 2009, September 27, 2008 and September 29, 2007...….................................. F-4
Consolidated Statements of Cash Flows –
Years Ended September 26, 2009, September 27, 2008 and September 29, 2007......................................... F-5
Consolidated Statements of Partners’ Capital –
Years Ended September 26, 2009, September 27, 2008 and September 29, 2007......................................... F-6
Notes to Consolidated Financial Statements........................…............................................................................. F-7
F-1
Report of Independent Registered Public Accounting Firm
To the Board of Supervisors and Unitholders of
Suburban Propane Partners, L.P.
In our opinion, the accompanying consolidated balance sheets and the related consolidated statement of operations,
partners' capital and of cash flows present fairly, in all material respects, the financial position of Suburban Propane
Partners, L.P. and its subsidiaries at September 26, 2009 and September 27, 2008, and the results of their operations
and their cash flows for each of the three years in the period ended September 26, 2009 in conformity with accounting
principles generally accepted in the United States of America. In addition, in our opinion, the financial statement
schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein
when read in conjunction with the related consolidated financial statements. Also in our opinion, the Partnership
maintained, in all material respects, effective internal control over financial reporting as of September 26, 2009, based
on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO). The Partnership's management is responsible for these financial
statements and financial statement schedules, for maintaining effective internal control over financial reporting and for
its assessment of the effectiveness of internal control over financial reporting, included in included in Management's
Report on Internal Control over Financial Reporting appearing in Item 9A. Our responsibility is to express opinions on
these financial statements, on the financial statement schedule, and on the Partnership's internal control over financial
reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to
obtain reasonable assurance about whether the financial statements are free of material misstatement and whether
effective internal control over financial reporting was maintained in all material respects. Our audits of the financial
statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates made by management, and evaluating the
overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an
understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing
and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also
included performing such other procedures as we considered necessary in the circumstances. We believe that our audits
provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding
the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with
generally accepted accounting principles. A company’s internal control over financial reporting includes those policies
and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are
recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting
principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of
management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on
the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may
deteriorate.
PricewaterhouseCoopers LLP
Florham Park, New Jersey
November 25, 2009
F-2
SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands)
ASSETS
Current assets:
Cash and cash equivalents
Accounts receivable, less allowance for doubtful accounts
of $4,374 and $6,578, respectively
Inventories
Other current assets
Total current assets
Property, plant and equipment, net
Goodwill
Other intangible assets, net
Other assets
Total assets
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Accounts payable
Accrued employment and benefit costs
Accrued insurance
Customer deposits and advances
Accrued interest
Other current liabilities
Total current liabilities
Long-term borrowings
Accrued insurance
Other liabilities
Total liabilities
Commitments and contingencies
September 26,
2009
September 27,
2008
$
163,173
$
137,698
52,035
70,158
22,190
307,556
357,187
274,897
13,798
24,076
977,514
$
$
35,677
40,875
10,410
65,769
7,294
20,034
180,059
349,415
41,838
46,485
617,797
94,933
79,822
47,098
359,551
367,808
276,282
16,018
16,054
1,035,713
$
$
58,079
27,053
41,120
71,206
11,030
17,568
226,056
531,772
31,913
25,896
815,637
Partners' capital:
Common Unitholders (35,228 and 32,725 units issued and outstanding at
September 26, 2009 and September 27, 2008, respectively)
Accumulated other comprehensive loss
Total partners' capital
Total liabilities and partners' capital
421,005
(61,288)
359,717
977,514
$
264,231
(44,155)
220,076
1,035,713
$
The accompanying notes are an integral part of these consolidated financial statements.
F-3
SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per unit amounts)
Revenues
Propane
Fuel oil and refined fuels
Natural gas and electricity
All other
Costs and expenses
Cost of products sold
Operating
General and administrative
Restructuring charges and severance costs
Depreciation and amortization
Income before loss on debt extinguishment, interest expense
and provision for income taxes
Loss on debt extinguishment
Interest income
Interest expense
Income before provision for income taxes
Provision for income taxes
Income from continuing operations
Discontinued operations:
Gain on disposal of discontinued operations
Income from discontinued operations
September
26, 2009
Year Ended
September
27, 2008
September
29, 2007
$
864,012
159,596
76,832
42,714
1,143,154
$
1,132,950
288,078
103,745
49,390
1,574,163
$
1,019,798
262,076
94,352
63,337
1,439,563
540,385
304,767
57,044
-
30,343
932,539
210,615
(4,624)
802
(39,069)
167,724
2,486
1,039,436
308,071
48,134
-
28,394
1,424,035
150,128
-
2,787
(39,839)
113,076
1,903
865,418
322,852
56,422
1,485
28,790
1,274,967
164,596
-
3,863
(39,459)
129,000
5,653
165,238
111,173
123,347
-
-
43,707
-
1,887
2,053
Net income
$
165,238
$
154,880
$
127,287
Income per Common Unit - basic
Income from continuing operations
Discontinued operations
Net income
Weighted average number of Common Units outstanding - basic
Income per Common Unit - diluted
Income from continuing operations
Discontinued operations
Net income
Weighted average number of Common Units outstanding - diluted
$
$
$
$
$
$
4.99
-
4.99
33,134
4.96
-
4.96
33,315
3.39
1.33
4.72
32,783
3.37
1.33
4.70
32,950
$
$
$
$
$
$
3.79
0.12
3.91
32,554
3.77
0.12
3.89
32,730
The accompanying notes are an integral part of these consolidated financial statements.
F-4
SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
Cash flows from operating activities:
Net income
Adjustments to reconcile net income to net cash provided by operations:
Depreciation and amortization expense
Depreciation expense - discontinued operations
Amortization of debt origination costs
Compensation cost recognized under Restricted Unit Plan
Amortization of discount on long-term borrowings
Gain on disposal of property, plant and equipment, net
Gain on disposal of discontinued operations
Pension settlement charge
Loss on debt extinguishment
Deferred tax provision
Changes in assets and liabilities
Decrease (increase) in accounts receivable
Decrease (increase) in inventories
Decrease (increase) in prepaid expenses and other current assets
(Decrease) increase in accounts payable
Increase (decrease) in accrued employment and benefit costs
(Decrease) increase in accrued insurance
(Decrease) increase in customer deposits and advances
(Decrease) increase in accrued interest
Increase (decrease) in other accrued liabilities
(Increase) decrease in other noncurrent assets
Increase (decrease) in other noncurrent liabilities
Contribution to defined benefit pension plan
Net cash provided by operating activities
Cash flows from investing activities:
Capital expenditures
Proceeds from sale of property, plant and equipment
Proceeds from sale of discontinued operations
Net cash (used in) provided by investing activities
Cash flows from financing activities:
Repayments of long-term borrowings (includes premium and fees)
Proceeds from long-term borrowings
Issuance costs associated with long-term borrowings
Repayments of short-term borrowings
Net proceeds from issuance of Common Units
Partnership distributions
Net cash (used in) financing activities
Net increase in cash and cash equivalents
Cash and cash equivalents at beginning of year
Cash and cash equivalents at end of year
September
26, 2009
Year Ended
September
27, 2008
September
29, 2007
$
165,238
$
154,880
$
127,287
30,343
-
1,923
2,396
226
(650)
-
-
4,624
1,385
42,898
9,664
24,908
(22,402)
13,822
(20,785)
(5,437)
(3,736)
4,466
(5,787)
3,455
-
246,551
(21,837)
4,985
-
(16,852)
28,394
-
1,328
2,156
234
(2,252)
(43,707)
-
-
1,277
(9,663)
1,424
(26,935)
1,080
(10,587)
27,240
(4,188)
2,484
5,307
2,810
(10,765)
-
120,517
(21,819)
4,734
53,715
36,630
28,790
452
1,327
3,014
234
(2,782)
(1,887)
3,269
-
3,800
(6,827)
(1,915)
(3,658)
(448)
3,551
6,520
12,780
175
(5,475)
(41,120)
43,870
(25,000)
145,957
(26,756)
5,783
1,284
(19,689)
(177,821)
100,000
(5,543)
(110,000)
95,880
(106,740)
(204,224)
25,475
137,698
163,173
$
(15,000)
-
-
-
-
(101,035)
(116,035)
41,112
96,586
137,698
$
-
-
-
-
-
(90,253)
(90,253)
36,015
60,571
96,586
$
Supplemental disclosure of cash flow information:
Cash paid for interest
$
39,153
$
35,217
$
37,165
The accompanying notes are an integral part of these consolidated financial statements.
F-5
SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(in thousands)
Number of
Common
Units
Common
Unitholders
General
Partner
Deferred
Compen-
sation
Common
Units Held
in Trust
Accumulated
Other
Compre-
hensive
(Loss) Income
Total
Partners'
Capital
Comprehensive
Income (Loss)
Balance at September 30, 2006
30,314
$
170,151
$
(1,969)
$
5,704
$
(5,704)
$
(67,481)
$
100,701
127,287
127,287
$
127,287
(173)
(173)
(173)
Net income
Other comprehensive income:
Net unrealized losses on cash flow hedges
Reclassification of realized losses on
cash flow hedges into earnings
Non-cash pension settlement charge
Minimum pension liability adjustment
Adjustment to initially adopt new benefits accounting standard
Total comprehensive income
Partnership distributions
Common Units issued under
Restricted Unit Plan
Common Units issued in
Exchange of GP interest
Exchange and cancellation of GP Interest
Common Units distributed from trust
Compensation cost recognized under
Restricted Unit Plan, net of forfeitures
60
2,300
(90,253)
80,443
(82,412)
1,969
3,014
(44)
44
1,967
3,269
63,510
-
$
195,860
1,967
3,269
63,510
(43,045)
1,967
3,269
63,510
(43,045)
(90,253)
80,443
(80,443)
-
3,014
Balance at September 29, 2007
32,674
$
208,230
$
-
$
5,660
$
(5,660)
$
(41,953)
$
166,277
Net income
Other comprehensive income:
Net unrealized losses on cash flow hedges
Reclassification of realized gains on
cash flow hedges into earnings
Amortization of net actuarial losses and prior
service credits into earnings and net
change in funded status of benefit plans
Total comprehensive income
Partnership distributions
Common Units issued under
Restricted Unit Plan
Common Units distributed from trust
Compensation cost recognized under
Restricted Unit Plan, net of forfeitures
154,880
154,880
$
154,880
(101,035)
51
2,156
(5,660)
5,660
(2,916)
(2,916)
(1,377)
(1,377)
(2,916)
(1,377)
2,091
2,091
$
2,091
152,678
(101,035)
-
2,156
Balance at September 27, 2008
32,725
$
264,231
$
-
$
-
$
-
$
(44,155)
$
220,076
Net income
Other comprehensive income:
Net unrealized losses on cash flow hedges
Amortization of net actuarial losses and prior
service credits into earnings and net
change in funded status of benefit plans
Total comprehensive income
Partnership distributions
Common Units issued under
Restricted Unit Plan
Sale of Common Units under
public offering, net of offering expenses
Compensation cost recognized under
Restricted Unit Plan, net of forfeitures
165,238
165,238
$
165,238
(106,740)
72
2,431
95,880
2,396
(991)
(991)
(991)
(16,142)
(16,142)
$
(16,142)
148,105
(106,740)
95,880
2,396
Balance at September 26, 2009
35,228
$
421,005
$
-
$
-
$
-
$
(61,288)
$
359,717
The accompanying notes are an integral part of these consolidated financial statements.
F-6
SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands, except per unit amounts)
1. Partnership Organization and Formation
Suburban Propane Partners, L.P. (the “Partnership”) is a publicly traded Delaware limited partnership principally
engaged, through its operating partnership and subsidiaries, in the retail marketing and distribution of propane,
fuel oil and refined fuels, as well as the marketing of natural gas and electricity in deregulated markets. In
addition, to complement its core marketing and distribution businesses, the Partnership services a wide variety of
home comfort equipment, particularly for heating and ventilation. The publicly traded limited partner interests in
the Partnership are evidenced by common units traded on the New York Stock Exchange (“Common Units”),
with 35,227,954 Common Units outstanding at September 26, 2009. The holders of Common Units are entitled
to participate in distributions and exercise the rights and privileges available to limited partners under the Third
Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”), adopted on October
19, 2006 following approval by Common Unitholders at the Partnership’s Tri-Annual Meeting and as thereafter
amended by the Board of Supervisors on July 31, 2007, pursuant to the authority granted to the Board in the
Partnership Agreement. Rights and privileges under the Partnership Agreement include, among other things, the
election of all members of the Board of Supervisors and voting on the removal of the general partner.
Suburban Propane, L.P. (the “Operating Partnership”), a Delaware limited partnership, is the Partnership’s
operating subsidiary formed to operate the propane business and assets. In addition, Suburban Sales & Service,
Inc. (the “Service Company”), a subsidiary of the Operating Partnership, was formed to operate the service work
and appliance and parts businesses of the Partnership. The Operating Partnership, together with its direct and
indirect subsidiaries, accounts for substantially all of the Partnership’s assets, revenues and earnings. The
Partnership, the Operating Partnership and the Service Company commenced operations in March 1996 in
connection with the Partnership’s initial public offering.
The general partner of both the Partnership and the Operating Partnership is Suburban Energy Services Group
LLC (the “General Partner”), a Delaware limited liability company. On October 19, 2006, the Partnership
consummated an agreement with its General Partner to exchange 2,300,000 newly issued Common Units for the
General Partner’s incentive distribution rights (“IDRs”) and the economic interest in the Partnership and the
Operating Partnership included in the general partner interests therein (the “GP Exchange Transaction”). Prior to
the GP Exchange Transaction, the General Partner was majority-owned by senior management of the Partnership
and owned 224,625 general partner units (an approximate 0.74% ownership interest) in the Partnership and a
1.0101% general partner interest in the Operating Partnership. The General Partner also held all outstanding
IDRs and appointed two members to the Board of Supervisors. As a result of the GP Exchange Transaction, the
General Partner no longer has any economic interest in either the Partnership or the Operating Partnership other
than as a holder of 784 Common Units that will remain in the General Partner, no IDRs are outstanding and the
sole member of the General Partner is the Partnership’s Chief Executive Officer.
During fiscal 2004, the Partnership acquired substantially all of the assets and operations of Agway Energy
Products, LLC, Agway Energy Services, Inc. and Agway Energy Services PA, Inc. (collectively referred to as
“Agway Energy”). The operations of Agway Energy consisted of the distribution and marketing of propane, fuel
oil and refined fuels, as well as the marketing of natural gas and electricity. The Partnership’s fuel oil and
refined fuels, natural gas and electricity and services businesses are structured as corporate entities (collectively
referred to as “Corporate Entities”) and, as such, are subject to corporate level income tax.
Suburban Energy Finance Corporation, a direct wholly-owned subsidiary of the Partnership, was formed on
November 26, 2003 to serve as co-issuer, jointly and severally with the Partnership, of the Partnership’s 6.875%
senior notes due in 2013.
F-7
The Partnership serves approximately 850,000 active residential, commercial, industrial and agricultural
customers from approximately 300 locations in 30 states. The Partnership’s operations are concentrated in the
east and west coast regions of the United States, including Alaska. No single customer accounted for 10% or
more of the Partnership’s revenues during fiscal 2009, 2008 or 2007.
2. Summary of Significant Accounting Policies
Principles of Consolidation. The consolidated financial statements include the accounts of the Partnership, the
Operating Partnership and all of its direct and indirect subsidiaries. All significant intercompany transactions
and account balances have been eliminated. As a result of the GP Exchange Transaction, the General Partner no
longer has any economic interest in the Partnership or the Operating Partnership apart from 784 Common Units
held by it. The Partnership consolidates the results of operations, financial condition and cash flows of the
Operating Partnership as a result of the Partnership’s 100% limited partner interest in the Operating Partnership.
Fiscal Period. The Partnership’s fiscal year ends on the last Saturday nearest to September 30.
Revenue Recognition. Sales of propane, fuel oil and refined fuels are recognized at the time product is delivered to
the customer. Revenue from the sale of appliances and equipment is recognized at the time of sale or when
installation is complete, as applicable. Revenue from repairs, maintenance and other service activities is recognized
upon completion of the service. Revenue from service contracts is recognized ratably over the service period.
Revenue from the natural gas and electricity business is recognized based on customer usage as determined by
meter readings, as adjusted for amounts delivered but unbilled at the end of each accounting period. Revenue
from annually billed tank fees is deferred at the time of billings and recognized on a straight-line basis over one
year.
Fair Value Measurements. On September 28, 2008, the Partnership adopted new accounting guidance on fair
value measurements. The Partnership measures certain of its assets and liabilities at fair value, which is defined
as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between
market participants – in either the principal market or the most advantageous market. The principal market is the
market with the greatest level of activity and volume for the asset or liability. Adoption of this new accounting
guidance did not impact the Partnership’s financial position, results of operations or cash flows.
The common framework for measuring fair value utilizes a three-level hierarchy to prioritize the inputs used in
the valuation techniques to derive fair values. The basis for fair value measurements for each level within the
hierarchy is described below with Level 1 having the highest priority and Level 3 having the lowest.
• Level 1: Quoted prices in active markets for identical assets or liabilities.
• Level 2: Quoted prices in active markets for similar assets or liabilities; quoted prices for identical or similar
instruments in markets that are not active; and model-derived valuations in which all significant inputs are
observable in active markets.
• Level 3: Valuations derived from valuation techniques in which one or more significant inputs are
unobservable.
The Partnership measures the fair value of its options and futures derivative instruments using Level 1 inputs and
the fair value of its interest rate swap using Level 2 inputs. See Derivative Instruments and Hedging Activities,
below, for additional information regarding fair value measurements.
Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting
principles (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts
of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements
and the reported amounts of revenues and expenses during the reporting period. Estimates have been made by
F-8
management in the areas of self-insurance and litigation reserves, pension and other postretirement benefit
liabilities and costs, valuation of derivative instruments, depreciation and amortization of long-lived assets, asset
impairment assessments, tax valuation allowances and allowances for doubtful accounts. Actual results could
differ from those estimates, making it reasonably possible that a material change in these estimates could occur in
the near term.
Cash and Cash Equivalents. The Partnership considers all highly liquid instruments purchased with an original
maturity of three months or less to be cash equivalents. The carrying amount approximates fair value because of
the short maturity of these instruments.
Inventories. Inventories are stated at the lower of cost or market. Cost is determined using a weighted average
method for propane, fuel oil and refined fuels and natural gas, and a standard cost basis for appliances, which
approximates average cost.
Derivative Instruments and Hedging Activities. On December 28, 2008, the Partnership adopted new
accounting guidance on disclosures about derivative instruments and hedging activities, which required enhanced
disclosures about an entity’s objectives for using derivative instruments (defined below) and related hedged
items, how those derivative instruments are accounted for and how derivative instruments and related hedged
items affect an entity’s financial position, financial performance and cash flows.
Commodity Price Risk. Given the retail nature of its operations, the Partnership maintains a certain level of
priced physical inventory to ensure its field operations have adequate supply commensurate with the time of year.
The Partnership’s strategy is to keep its physical inventory priced relatively close to market for its field
operations. The Partnership enters into a combination of exchange-traded futures and option contracts, forward
contracts and, in certain instances, over-the-counter option contracts (collectively, “derivative instruments”) to
hedge price risk associated with propane and fuel oil physical inventory, as well as future purchases of propane
or fuel oil used in its operations and to ensure adequate supply during periods of high demand. Under this risk
management strategy, realized gains or losses on derivative instruments will typically offset losses or gains on
the physical inventory once the product is sold. All of the Partnership’s derivative instruments are reported on
the consolidated balance sheet at their fair values. In addition, in the course of normal operations, the
Partnership routinely enters into contracts such as forward priced physical contracts for the purchase or sale of
propane and fuel oil that qualify for and are designated as normal purchase or normal sale contracts. Such
contracts are exempted from the fair value accounting requirements and are accounted for at the time product is
purchased or sold under the related contract. The Partnership does not use derivative instruments for speculative
trading purposes. Market risks associated with futures, options and forward contracts are monitored daily for
compliance with the Partnership’s Hedging and Risk Management Policy which includes volume limits for open
positions. Priced on-hand inventory is also reviewed and managed daily as to exposures to changing market
prices.
On the date that futures, forward and option contracts are entered into, other than those designated as normal
purchases or normal sales, the Partnership makes a determination as to whether the derivative instrument
qualifies for designation as a hedge. Changes in the fair value of derivative instruments are recorded each period
in current period earnings or other comprehensive income (loss) (“OCI”), depending on whether the derivative
instrument is designated as a hedge and, if so, the type of hedge. For derivative instruments designated as cash
flow hedges, the Partnership formally assesses, both at the hedge contract’s inception and on an ongoing basis,
whether the hedge contract is highly effective in offsetting changes in cash flows of hedged items. Changes in
the fair value of derivative instruments designated as cash flow hedges are reported in OCI to the extent effective
and reclassified into cost of products sold during the same period in which the hedged item affects earnings. The
mark-to-market gains or losses on ineffective portions of cash flow hedges used to hedge future purchases are
recognized in cost of products sold immediately. Changes in the fair value of derivative instruments that are not
designated as cash flow hedges, and that do not meet the normal purchase and normal sale exemption, are
recorded within cost of products sold as they occur. Cash flows associated with derivative instruments are
F-9
reported as operating activities within the consolidated statement of cash flows.
Interest Rate Risk. A portion of the Partnership’s borrowings bear interest at prevailing interest rates based upon,
at the Operating Partnership’s option, LIBOR plus an applicable margin or the base rate, defined as the higher of
the Federal Funds Rate plus ½ of 1% or the agent bank’s prime rate, or LIBOR plus 1%, plus the applicable
margin. The applicable margin is dependent on the level of the Partnership’s total leverage (the ratio of total
debt to income before deducting interest expense, income taxes, depreciation and amortization (“EBITDA”)).
Therefore, the Partnership is subject to interest rate risk on the variable component of the interest rate. The
Partnership manages part of its variable interest rate risk by entering into interest rate swap agreements. The
interest rate swaps have been designated as and are accounted for as, cash flow hedges. Changes in the fair value
of the interest rate swaps are recognized in OCI until the hedged items are recognized in earnings. However, due
to changes in the underlying interest rate environment, the corresponding value in OCI is subject to change prior
to its impact on earnings.
Long-Lived Assets.
Property, plant and equipment. Property, plant and equipment are stated at cost. Expenditures for maintenance and
routine repairs are expensed as incurred while betterments are capitalized as additions to the related assets and
depreciated over the asset’s remaining useful life. The Partnership capitalizes costs incurred in the acquisition and
modification of computer software used internally, including consulting fees and costs of employees dedicated
solely to a specific project. At the time assets are retired, or otherwise disposed of, the asset and related
accumulated depreciation are removed from the accounts, and any resulting gain or loss is recognized within
operating expenses. Depreciation is determined under the straight-line method based upon the estimated useful life
of the asset as follows:
Buildings
Building and land improvements
Transportation equipment
Storage facilities
Office equipment
Tanks and cylinders
Computer software
40 Years
20-40 Years
4-20 Years
7-40 Years
5-10 Years
15-40 Years
3-7 Years
The weighted average estimated useful life of the Partnership’s tanks and cylinders is approximately 25 years.
The Partnership reviews the recoverability of long-lived assets when circumstances occur that indicate that the
carrying value of an asset may not be recoverable. Such circumstances include a significant adverse change in the
manner in which an asset is being used, current operating losses combined with a history of operating losses
experienced by the asset or a current expectation that an asset will be sold or otherwise disposed of before the end of
its previously estimated useful life. Evaluation of possible impairment is based on the Partnership’s ability to
recover the value of the asset from the future undiscounted cash flows expected to result from the use and eventual
disposition of the asset. If the expected undiscounted cash flows are less than the carrying amount of such asset, an
impairment loss is recorded as the amount by which the carrying amount of an asset exceeds its fair value. The fair
value of an asset will be measured using the best information available, including prices for similar assets or the
result of using a discounted cash flow valuation technique.
Goodwill. Goodwill represents the excess of the purchase price over the fair value of net assets acquired. Goodwill
is subject to an impairment review at a reporting unit level, on an annual basis in August of each year, or when
an event occurs or circumstances change that would indicate potential impairment. The Partnership assesses the
carrying value of goodwill at a reporting unit level based on an estimate of the fair value of the respective
reporting unit. Fair value of the reporting unit is estimated using discounted cash flow analyses taking into
consideration estimated cash flows in a ten-year projection period and a terminal value calculation at the end of
F-10
the projection period. If the fair value of the reporting unit exceeds its carrying value, the goodwill associated
with the reporting unit is not considered to be impaired. If the carrying value of the reporting unit exceeds its
fair value, an impairment loss is recognized to the extent that the carrying amount of the associated goodwill, if
any, exceeds the implied fair value of the goodwill.
Other Intangible Assets. Other intangible assets consist of customer lists, tradenames, non-compete agreements
and leasehold interests. Customer lists and tradenames are amortized under the straight-line method over the
estimated period for which the assets are expected to contribute to the future cash flows of the reporting entities
to which they relate, ending periodically between fiscal years 2012 and 2019. Non-compete agreements are
amortized under the straight-line method over the periods of the related agreements, which ended in fiscal year
2009. Leasehold interests are amortized under the straight-line method over the shorter of the lease term or the
useful life of the related assets, through fiscal 2025.
Accrued Insurance. Accrued insurance represents the estimated costs of known and anticipated or unasserted
claims for self-insured liabilities related to general and product, workers’ compensation and automobile liability.
Accrued insurance provisions for unasserted claims arising from unreported incidents are based on an analysis of
historical claims data. For each claim, the Partnership records a provision up to the estimated amount of the
probable claim utilizing actuarially determined loss development factors applied to actual claims data. The
Partnership maintains insurance coverage such that its net exposure for insured claims is limited to the insurance
deductible, claims above which are paid by the Partnership’s insurance carriers. For the portion of the estimated
liability that exceeds insurance deductibles, the Partnership records an asset related to the amount of the liability
expected to be covered by insurance. Claims are generally settled within five years of origination.
Customer Deposits and Advances. The Partnership offers different payment programs to its customers including
the ability to prepay for usage and to make equal monthly payments on account under a budget payment plan. The
Partnership establishes a liability within customer deposits and advances for amounts collected in advance of
deliveries.
Income Taxes. As discussed in Note 1, the Partnership structure consists of two limited partnerships, the
Partnership and the Operating Partnership, and several Corporate Entities. For federal income tax purposes, as well
as for state income tax purposes in the majority of the states in which the Partnership operates, the earnings
attributable to the Partnership and the Operating Partnership are included in the tax returns of the individual
partners. As a result, except for certain states that impose an income tax on partnerships, no income tax expense is
reflected in the Partnership’s consolidated financial statements relating to the earnings of the Partnership and the
Operating Partnership. The earnings attributable to the Corporate Entities are subject to federal and state income
taxes. Net earnings for financial statement purposes may differ significantly from taxable income reportable to
Common Unitholders as a result of differences between the tax basis and financial reporting basis of assets and
liabilities and the taxable income allocation requirements under the Partnership Agreement.
Income taxes for the Corporate Entities are provided based on the asset and liability approach to accounting for
income taxes. Under this method, deferred tax assets and liabilities are recognized for the expected future tax
consequences of differences between the carrying amounts and the tax basis of assets and liabilities using enacted
tax rates in effect for the year in which the differences are expected to reverse. The effect on deferred tax assets and
liabilities of a change in tax rates is recognized in income in the period when the change is enacted. A valuation
allowance is recorded to reduce the carrying amounts of deferred tax assets when it is more likely than not that the
full amount will not be realized.
Asset Retirement Obligations. Asset retirement obligations apply to legal obligations associated with the
retirement of long-lived assets that result from the acquisition, construction, development and/or the normal
operation of a long-lived asset, except for certain obligations of lessees. The Partnership has recognized asset
retirement obligations for certain costs to remove and properly dispose of underground and aboveground fuel oil
storage tanks and contractually mandated removal of leasehold improvements.
F-11
The Partnership records a liability at fair value for the estimated cost to settle an asset retirement obligation at the
time that liability is incurred, which is generally when the asset is purchased, constructed or leased. The
Partnership records the liability, which is referred to as the asset retirement obligation, when it has a legal
obligation to incur costs to retire the asset and when a reasonable estimate of the fair value of the liability can be
made. If a reasonable estimate cannot be made at the time the liability is incurred, the Partnership records the
liability when sufficient information is available to estimate the liability’s fair value.
Unit-Based Compensation. The Partnership recognizes compensation cost over the respective service period for
employee services received in exchange for an award of equity or equity-based compensation based on the grant
date fair value of the award. The Partnership measures liability awards under an equity-based payment
arrangement based on remeasurement of the award’s fair value at the conclusion of each interim and annual
reporting period until the date of settlement, taking into consideration the probability that the performance
conditions will be satisfied.
Costs and Expenses. The cost of products sold reported in the consolidated statements of operations represents
the weighted average unit cost of propane, fuel oil and refined fuels, as well as the cost of natural gas and
electricity sold, including transportation costs to deliver product from the Partnership’s supply points to storage
or to the Partnership’s customer service centers. Cost of products sold also includes the cost of appliances,
equipment and related parts sold or installed by the Partnership’s customer service centers computed on a basis
that approximates the average cost of the products. Unrealized (non-cash) gains or losses from changes in the
fair value of derivative instruments that are not designated as cash flow hedges are recorded in each reporting
period within cost of products sold. Cost of products sold is reported exclusive of any depreciation and
amortization as such amounts are reported separately within the consolidated statements of operations.
All other costs of operating the Partnership’s retail propane, fuel oil and refined fuels distribution and appliance
sales and service operations, as well as the natural gas and electricity marketing business, are reported within
operating expenses in the consolidated statements of operations. These operating expenses include the
compensation and benefits of field and direct operating support personnel, costs of operating and maintaining the
vehicle fleet, overhead and other costs of the purchasing, training and safety departments and other direct and
indirect costs of operating the Partnership’s customer service centers.
All costs of back office support functions, including compensation and benefits for executives and other support
functions, as well as other costs and expenses to maintain finance and accounting, treasury, legal, human
resources, corporate development and the information systems functions are reported within general and
administrative expenses in the consolidated statements of operations.
Net Income Per Unit. Subsequent to the GP Exchange Transaction, computations of basic income per Common
Unit are performed by dividing net income by the weighted average number of outstanding Common Units, and
restricted units granted under the Restricted Unit Plans to retirement-eligible grantees. Computations of diluted
income per Common Unit are performed by dividing net income by the weighted average number of outstanding
Common Units and unvested restricted units granted under the Restricted Unit Plans. Prior to the GP Exchange
Transaction, when the General Partner’s interest included IDRs in the Partnership, computations of earnings per
Common Unit were performed, when applicable, using the two-class method when participating securities
existed. The two-class method is an earnings allocation formula that computes earnings per unit for each class of
Common Unit and participating security according to distributions declared and the participating rights in
undistributed earnings, as if all of the earnings were distributed to the limited partners and the General Partner
(inclusive of the IDRs of the General Partner which were considered participating securities for purposes of the
two-class method). Net income was allocated to the Common Unitholders and the General Partner in accordance
with their respective Partnership ownership interests, after giving effect to any priority income allocations for
incentive distributions allocated to the General Partner. For purposes of the computation of income per Common
Unit for the year ended September 29, 2007, earnings that would have been allocated to the General Partner for
the period prior to the GP Exchange Transaction were not significant. Following the GP Exchange Transaction
F-12
consummated on October 19, 2006, the two-class method of computing income per Common Unit was no longer
applicable.
In computing diluted net income per Common Unit, weighted average units outstanding used to compute basic
net income per Common Unit were increased by 180,789, 166,308 and 175,701 units for the years ended
September 26, 2009, September 27, 2008 and September 29, 2007, respectively, to reflect the potential dilutive
effect of the unvested restricted units outstanding using the treasury stock method.
Comprehensive Income. The Partnership reports comprehensive (loss) income (the total of net income and all
other non-owner changes in partners’ capital) within the consolidated statement of partners’ capital.
Comprehensive (loss) income includes unrealized gains and losses on derivative instruments accounted for as
cash flow hedges, minimum pension liability adjustments and changes in the funded status of pension and other
postretirement benefit plans.
Recently Issued Accounting Standards. In December 2008, the Financial Accounting Standards Board
(“FASB”) issued new financial reporting guidance to require more detailed disclosures about employers’ pension
plan assets. These new disclosures will include more information on investment strategies, major categories of
plan assets, concentrations of risk within plan assets and valuation techniques used to measure the fair value of
plan assets. The new guidance is effective for fiscal years ending after December 15, 2009, which will be the
Partnership’s 2010 fiscal year ending September 25, 2010. Since it only addresses disclosures, the adoption of
the new guidance is not expected to have an impact on the Partnership’s consolidated financial position, results
of operations or cash flows.
In December 2007, the FASB issued revised accounting guidance concerning business combinations. Among
other things, this revised guidance requires an entity to recognize acquired assets, liabilities assumed and any
noncontrolling interest at their respective fair values as of the acquisition date, clarifies how goodwill involved in
a business combination is to be recognized and measured, as well as requires the expensing of acquisition-related
costs as incurred. Most of its provisions are effective for business combinations entered into in fiscal years
beginning on or after December 15, 2008, which will be the Partnership’s 2010 fiscal year beginning September
27, 2009, with early adoption prohibited. Certain provisions, in particular a provision related to the accounting
for acquired tax benefits, are required to be applied in future fiscal years regardless of when the business
combination occurred. To the extent the Partnership’s Corporate Entities generate taxable profits in future years
that enable the utilization of tax benefits acquired in the Agway Energy acquisition, the corresponding reduction
in the valuation allowance will be recorded as a reduction in the provision for income taxes.
Reclassifications. Certain prior period amounts have been reclassified to conform with the current period
presentation. In addition, other current liabilities were increased and other liabilities were reduced as of September
27, 2008 by $2,441 to reclassify the current portion of the interest rate swap liability.
Subsequent Events. The Partnership has evaluated all subsequent events that occurred after the balance sheet
date through November 25, 2009, the date its financial statements were issued, and concluded there were no
events or transactions occurring during this period that required recognition or disclosure in its financial
statements.
3. Distributions of Available Cash
The Partnership makes distributions to its partners no later than 45 days after the end of each fiscal quarter of the
Partnership in an aggregate amount equal to its Available Cash for such quarter. Available Cash, as defined in
the Partnership Agreement, generally means all cash on hand at the end of the respective fiscal quarter less the
amount of cash reserves established by the Board of Supervisors in its reasonable discretion for future cash
requirements. These reserves are retained for the proper conduct of the Partnership’s business, the payment of
debt principal and interest and for distributions during the next four quarters.
F-13
Prior to October 19, 2006, the General Partner had IDRs which represented an incentive for the General Partner
to increase distributions to Common Unitholders in excess of the target quarterly distribution of $0.55 per
Common Unit. With regard to the first $0.55 of quarterly distributions paid in any given quarter, 98.26% of the
Available Cash was distributed to the Common Unitholders and 1.74% was distributed to the General Partner.
With regard to the balance of quarterly distributions in excess of the $0.55 per Common Unit target distribution,
85% of the Available Cash was distributed to the Common Unitholders and 15% was distributed to the General
Partner. As a result of the GP Exchange Transaction, the IDRs were cancelled and the General Partner is no
longer entitled to receive any cash distributions in respect of its general partner interests. Accordingly, beginning
with the quarterly distribution paid on November 14, 2006 in respect of the fourth quarter of fiscal 2006, 100%
of all cash distributions are paid to holders of Common Units.
The following summarizes the quarterly distributions per Common Unit declared and paid in respect of each of
the quarters in the three fiscal years in the period ended September 26, 2009:
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
Fiscal
2009
Fiscal
2008
Fiscal
2007
$
0.8100
0.8150
0.8250
0.8300
$
0.7625
0.7750
0.8000
0.8050
$
0.6875
0.7000
0.7125
0.7500
On October 22, 2009, the Board of Supervisors declared a quarterly distribution of $0.830 per Common Unit, or
$3.32 per Common Unit on an annualized basis, in respect of the fourth quarter of fiscal 2009, which was paid on
November 10, 2009 to holders of record on November 3, 2009. This quarterly distribution included an increase
of $0.005 per Common Unit, or $0.02 per Common Unit on an annualized basis, from the previous distribution
rate established in July, 2009, and an increase of $0.0250 per Common Unit, or $0.10 per Common Unit on an
annualized basis, from the prior year-end distribution rate.
4. Selected Balance Sheet Information
Inventories consist of the following:
Propane and refined fuels
Natural gas
Appliances and related parts
As of
September 26,
2009
September 27,
2008
$
$
67,293
219
2,646
70,158
76,036
283
3,503
79,822
$
$
The Partnership enters into contracts to buy propane, fuel oil and natural gas for supply purposes. Such contracts
generally have a term of one year subject to annual renewal, with costs based on market prices at the date of
delivery.
F-14
Property, plant and equipment consist of the following:
As of
September 26,
2009
September 27,
2008
Land and improvements
Buildings and improvements
Transportation equipment
Storage facilities
Equipment, primarily tanks and cylinders
Computer systems
Construction in progress
Less: accumulated depreciation
$
$
28,452
78,189
33,231
76,594
471,787
43,538
2,657
734,448
377,261
357,187
28,307
77,833
35,033
74,954
463,332
41,796
1,711
722,966
355,158
367,808
$
$
Depreciation expense from continuing operations for the years ended September 26, 2009, September 27, 2008 and
September 29, 2007 amounted to $28,123, $26,170 and $26,547, respectively. Depreciation expense from
discontinued operations for the years ended September 26, 2009, September 27, 2008 and September 29, 2007
amounted to $-0-, $-0- and $452, respectively.
5. Goodwill and Other Intangible Assets
The Partnership’s fiscal 2009 and fiscal 2008 annual goodwill impairment review resulted in no adjustments to
the carrying amount of goodwill. During fiscal 2009 and fiscal 2008, the Partnership reversed $1,385 and $1,277
of the deferred tax asset valuation allowance, respectively, which was established through purchase accounting
for the Agway Acquisition, as a reduction to goodwill. This adjustment resulted from the utilization of a portion
of the net operating losses established in purchase accounting for the Agway Acquisition. The carrying value of
goodwill assigned to the Partnership’s operating segments are as follows:
As of
September 26,
2009
September 27,
2008
$
$
262,559
4,438
7,900
274,897
262,559
5,823
7,900
276,282
$
$
Propane
Fuel oil and refined fuels
Natural gas and electricity
F-15
Other intangible assets, the majority of which were acquired in the Agway Acquisition, consist of the following:
Customer lists
Tradenames
Other
Less: accumulated amortization
Customer lists
Tradenames
Other
As of
September 26,
2009
September 27,
2008
$
22,316
1,499
1,967
25,782
$
22,316
1,499
2,117
25,932
(10,596)
(862)
(526)
(11,984)
13,798
$
(8,632)
(712)
(570)
(9,914)
16,018
$
Aggregate amortization expense related to other intangible assets for the years ended September 26, 2009,
September 27, 2008 and September 29, 2007 was $2,220, $2,224 and $2,243, respectively. Aggregate
amortization expense related to other intangible assets for each of the five succeeding fiscal years as of
September 26, 2009 is as follows: 2010 - $2,205; 2011 - $2,205; 2012 - $1,730; 2013 - $1,572 and 2014 - $1,237.
6. Restructuring Charges and Severance Costs
During fiscal 2007, payments for severance and other employee costs associated with a previously approved and
initiated plan of reorganization totaled $1,621 and were charged against the reserves established. As of
September 29, 2007, the reserve for severance and other employee benefits was fully utilized.
For the years ended September 26, 2009 and September 27, 2008, the Partnership did not record any
restructuring charges. For the year ended September 29, 2007, the Partnership incurred severance charges of
$1,485 associated with positions eliminated during fiscal 2007 unrelated to a specific plan of restructuring.
7. Income Taxes
For federal income tax purposes, as well as for state income tax purposes in the majority of the states in which the
Partnership operates, the earnings attributable to the Partnership, as a separate legal entity, and the Operating
Partnership are not subject to income tax at the partnership level. Rather, the taxable income or loss attributable
to the Partnership, as a separate legal entity, and to the Operating Partnership, which may vary substantially from
the income (loss) before income taxes reported by the Partnership in the consolidated statement of operations, are
includable in the federal and state income tax returns of the individual partners. The aggregate difference in the
basis of the Partnership’s net assets for financial and tax reporting purposes cannot be readily determined as the
Partnership does not have access to information regarding each partner’s basis in the Partnership.
The earnings of the Corporate Entities that do not qualify under the Internal Revenue Code for partnership status
are subject to federal and state income taxes. The Partnership’s fuel oil and refined fuels, natural gas and
electricity and services business segments are structured as corporate entities and, as such, are subject to
corporate level income tax. However, a number of those corporate entities have experienced operating losses in
recent years and, as a result, a full valuation allowance has been provided against the deferred tax assets. As a
result, at present, many of those Corporate Entities do not report a tax provision. The conclusion that a full
valuation allowance is necessary was based upon an analysis of all available evidence, both negative and positive at
F-16
the balance sheet date, which, taken as a whole, indicates that it is more likely than not that sufficient future taxable
income will not be available to utilize the Partnership’s deferred tax assets. Management’s periodic reviews include,
among other things, the nature and amount of the taxable income and expense items, the expected timing when
assets will be used or liabilities will be required to be reported and the reliability of historical profitability of
businesses expected to provide future earnings. Furthermore, management considered tax-planning strategies it
could use to increase the likelihood that the deferred tax assets will be realized.
The income tax provision of all the legal entities included in the Partnership’s consolidated statement of
operations consists of the following:
September 26,
2009
Year Ended
September 27,
2008
September 29,
2007
Current
Federal
State and local
Deferred
$
$
$
173
928
1,101
1,385
2,486
73
553
626
1,277
1,903
474
1,379
1,853
3,800
5,653
$
$
$
As a result of the calendar year 2009, 2008 and 2007 projected profitability of the Partnership’s Corporate
Entities, the Partnership reported taxable income and, as a result, utilized net operating losses to offset the
current cash tax liability. Utilization of these net operating losses resulted in a deferred tax provision of $1,385,
$1,277 and $3,800 in fiscal 2009, 2008 and 2007, respectively, and a corresponding reversal of a portion of the
valuation allowance established in purchase accounting for the acquisition of Agway Energy, which reduced
goodwill.
The provision for income taxes differs from income taxes computed at the United States federal statutory rate as
a result of the following:
Income tax provision at federal statutory tax rate
Impact of Partnership income not subject to
federal income taxes
Permanent differences
Change in valuation allowance
State income taxes
Alternative minimum tax
Other, net
Provision for income taxes - current and deferred
September 26,
2009
Year Ended
September 27,
2008
September 29,
2007
$
58,704
$
39,577
$
45,149
(56,294)
719
(2,048)
1,262
143
-
2,486
$
(45,323)
1,240
6,930
(572)
53
(2)
1,903
$
(39,459)
(358)
(1,583)
1,379
447
78
5,653
$
F-17
The components of net deferred taxes and the related valuation allowance using current enacted tax rates are as
follows:
Deferred tax assets:
Net operating loss carryforwards
Allowance for doubtful accounts
Inventory
Intangible assets
Deferred revenue
Derivative instruments
AMT credit carryforward
Other accruals
Total deferred tax assets
Deferred tax liabilities:
Derivative instruments
Property, plant and equipment
Total deferred tax liabilities
Net deferred tax assets
Valuation allowance
Net deferred tax assets
As of
September 26,
2009
September 27,
2008
$
38,995
679
833
1,523
1,613
-
789
2,915
47,347
$
41,768
1,428
722
1,127
1,787
92
646
2,083
49,653
1,282
603
1,885
45,462
(45,462)
$
-
-
758
758
48,895
(48,895)
$
-
As of September 26, 2009, the Partnership’s Corporate Entities had tax loss carryforwards for federal income tax
reporting purposes of approximately $96,025, which are available to offset future federal taxable income and expire
between 2024 and 2028.
8. Long-Term Borrowings
Short-term and long-term borrowings consist of the following:
Senior Notes, 6.875%, due December 15, 2013,
net of unamortized discount of $585 and $1,228, respectively
Revolving Credit Agreement, due June 25, 2013
Term Loan
Less: current portion of Term Loan
As of
September 26,
2009
September 27,
2008
$
$
249,415
100,000
-
349,415
-
349,415
423,772
-
110,000
533,772
2,000
531,772
$
$
The Partnership and its subsidiary, Suburban Energy Finance Corporation, have issued $425,000 aggregate
principal amount of Senior Notes (the “2003 Senior Notes) with an annual interest rate of 6.875%. On
September 9, 2009, the Partnership and its subsidiary purchased $175,000 aggregate principal amount of the
2003 Senior Notes through a cash tender offer. In connection with the tender offer, the Partnership recognized a
loss on the extinguishment of debt of $4,624 in the fourth quarter of fiscal 2009, consisting of $2,821 for the
tender premium and related fees, as well as the write-off of $1,803 in unamortized debt origination costs and
unamortized discount.
F-18
The Partnership’s obligations under the 2003 Senior Notes are unsecured and rank senior in right of payment to
any future subordinated indebtedness and equally in right of payment with any future senior indebtedness. The
2003 Senior Notes are structurally subordinated to, which means they rank effectively behind, any debt and other
liabilities of the Operating Partnership. The Senior Notes mature on December 15, 2013 and require semi-annual
interest payments in June and December. The Partnership is permitted to redeem some or all of the 2003 Senior
Notes any time at redemption prices specified in the indenture governing the 2003 Senior Notes. In addition, in
the event of a change of control of the Partnership, as defined in the indenture governing the 2003 Senior Notes,
the Partnership must offer to repurchase the notes at 101% of the principal amount repurchased, if the holders of
the notes exercise the right of repurchase.
On June 26, 2009, the Operating Partnership executed a Credit Agreement (the “Credit Agreement”) to provide a
four-year $250,000 revolving credit facility (the “Revolving Credit Facility”). The Credit Agreement replaces the
Operating Partnership’s previous credit facility, which provided for a $108,000 term loan (the “Term Loan”) and
a separate $175,000 working capital facility both of which, as amended, were scheduled to mature in March
2010. Borrowings under the Revolving Credit Facility may be used for general corporate purposes, including
working capital, capital expenditures and acquisitions until maturity on June 25, 2013. The Operating
Partnership has the right to prepay any borrowings under the Revolving Credit Facility, in whole or in part,
without penalty at any time prior to maturity. At closing, the Operating Partnership borrowed $100,000 under
the Revolving Credit Facility and, along with cash on hand, repaid the $108,000 then outstanding under the Term
Loan and terminated the previous credit facility. In addition, the Partnership has standby letters of credit issued
under the Revolving Credit Facility in the aggregate amount of $57,166 primarily in support of retention levels
under its self-insurance programs, which expire periodically through April 15, 2010. Therefore, as of September
26, 2009 the Partnership had available borrowing capacity of $92,834 under the Revolving Credit Facility.
Borrowings under the Revolving Credit Facility bear interest at prevailing interest rates based upon, at the
Operating Partnership’s option, LIBOR plus the applicable margin or the base rate, defined as the higher of the
Federal Funds Rate plus ½ of 1%, the agent bank’s prime rate, or LIBOR plus 1%, plus in each case the
applicable margin. The applicable margin is dependent upon the Partnership’s ratio of total debt to EBITDA on
a consolidated basis, as defined in the Revolving Credit Facility. As of September 26, 2009, the interest rate for
the Revolving Credit Facility was approximately 4.1%. The interest rate and the applicable margin will be reset
at the end of each calendar quarter.
The Partnership acts as a guarantor with respect to the obligations of the Operating Partnership under the Credit
Agreement pursuant to the terms and conditions set forth therein. The obligations under the Credit Agreement
are secured by liens on substantially all of the personal property of the Partnership, the Operating Partnership and
their subsidiaries, as well as mortgages on certain real property.
In connection with the Revolving Credit Facility, the Operating Partnership amended its existing interest rate
swap agreement, which has a termination date of March 31, 2010, to reduce the notional amount to $100,000
from $108,000. The Operating Partnership will pay a fixed interest rate of 4.66% to the issuing lender on the
notional principal amount outstanding, effectively fixing the LIBOR portion of the interest rate at 4.66%. In
return, the issuing lender will pay to the Operating Partnership a floating rate, namely LIBOR, on the same
notional principal amount. On July 31, 2009 our Operating Partnership entered into a forward starting interest
rate swap agreement with a March 31, 2010 effective date, which is commensurate with the maturity of the
existing interest rate swap agreement, and termination date of June 25, 2013. Under the forward starting interest
rate swap agreement, the Operating Partnership will pay a fixed interest rate of 3.12% to the issuing lender on
the notional principal amount outstanding, effectively fixing the LIBOR portion of the interest rate at 3.12%. In
return, the issuing lender will pay to the Operating Partnership a floating rate, namely LIBOR, on the same
notional principal amount. The interest rate swaps have been designated as a cash flow hedge.
F-19
The Revolving Credit Facility and the 2003 Senior Notes both contain various restrictive and affirmative
covenants applicable to the Operating Partnership and the Partnership, respectively, including (i) restrictions on
the incurrence of additional indebtedness, and (ii) restrictions on certain liens, investments, guarantees, loans,
advances, payments, mergers, consolidations, distributions, sales of assets and other transactions. The Revolving
Credit Facility contains certain financial covenants (a) requiring the consolidated interest coverage ratio, as
defined, of the Partnership to be not less than 2.5 to 1.0 as of the end of any fiscal quarter; (b) prohibiting the
total consolidated leverage ratio, as defined, of the Partnership from being greater than 4.5 to 1.0 as of the end of
any fiscal quarter; and (c) prohibiting the senior secured consolidated leverage ratio, as defined, of the Operating
Partnership from being greater than 3.0 to 1.0 as of the end of any fiscal quarter. Under the 2003 Senior Note
indenture, the Partnership is generally permitted to make cash distributions equal to available cash, as defined, as
of the end of the immediately preceding quarter, if no event of default exists or would exist upon making such
distributions, and the Partnership’s consolidated fixed charge coverage ratio, as defined, is greater than 1.75 to 1.
The Partnership and the Operating Partnership were in compliance with all covenants and terms of the 2003
Senior Notes and the Revolving Credit Facility as of September 26, 2009.
Debt origination costs representing the costs incurred in connection with the placement of, and the subsequent
amendment to, long-term borrowings are capitalized within other assets and amortized on a straight-line basis
over the term of the respective debt agreements. Other assets at September 26, 2009 and September 27, 2008
include debt origination costs with a net carrying amount of $7,136 and $4,902, respectively. Aggregate
amortization expense related to deferred debt origination costs included within interest expense for the years
ended September 26, 2009, September 27, 2008 and September 29, 2007 was $1,923, $1,328 and $1,327,
respectively. Unamortized debt origination costs of $414 associated with the previous credit facility were
written-off in the third quarter of fiscal 2009 and unamortized debt origination costs of $1,385 associated with
the tender offer of the 2003 Senior Notes were written-off in the fourth quarter of fiscal 2009.
The aggregate amounts of long-term debt maturities in fiscal years subsequent to September 26, 2009 are as
follows: 2010 through 2012 - $-0-; 2013 - $100,000; 2014 - $250,000; and thereafter - $-0-.
Under the previous credit facility, proceeds from the sale, transfer or other disposition of any asset of the
Operating Partnership, other than the sale of inventory in the ordinary course of business, in excess of $15,000
was required to be used to acquire productive assets within twelve months of receipt of the proceeds. Any
proceeds not used within twelve months of receipt to acquire productive assets were required to be used to
prepay the outstanding principal of the Term Loan. On September 26, 2008 and November 10, 2008, the
Operating Partnership prepaid $15,000 and $2,000, respectively, on the Term Loan with the net proceeds from
the sale of the Tirzah storage facility that were not used to acquire productive assets within twelve months of
receipt.
9. Unit-Based Compensation Arrangements
As described in Note 2, the Partnership recognizes compensation cost over the respective service period for
employee services received in exchange for an award of equity, or equity-based compensation, based on the grant
date fair value of the award. The Partnership measures liability awards under an equity-based payment
arrangement based on remeasurement of the award’s fair value at the conclusion of each interim and annual
reporting period until the date of settlement, taking into consideration the probability that the performance
conditions will be satisfied. The Partnership has historically recognized unearned compensation associated with
awards under its Restricted Unit Plans ratably to expense over the vesting period based on the fair value of the
award on the grant date and has historically recognized compensation cost and the associated unearned
compensation liability for equity-based awards under its Long-Term Incentive Plan.
Restricted Unit Plans. In fiscal 2000 and fiscal 2009, the Partnership adopted the Suburban Propane Partners,
L.P. 2000 Restricted Unit Plan and 2009 Restricted Unit Plan (collectively, the “Restricted Unit Plans”),
respectively, which authorizes the issuance of Common Units to executives, managers and other employees and
F-20
members of the Board of Supervisors of the Partnership. The total number of Common Units authorized for
issuance under the Restricted Unit Plans is 1,917,805. Unless otherwise stipulated by the compensation
committee on or before the grant date, Restricted Units issued under the Restricted Unit Plans vest over time with
25% of the Common Units vesting at the end of each of the third and fourth anniversaries of the grant date and
the remaining 50% of the Common Units vesting at the end of the fifth anniversary of the grant date. The
Restricted Unit Plans participants are not eligible to receive quarterly distributions or vote their respective
restricted units until vested. Because each restricted unit represents a promise to issue a Common Unit at a
future date, restricted units cannot be sold or transferred prior to vesting. The value of the restricted unit is
established by the market price of the Common Unit on the date of grant, net of estimated future distributions
during the vesting period. Restricted units are subject to forfeiture in certain circumstances as defined in the
Restricted Unit Plans. Compensation expense for the unvested awards is recognized ratably over the vesting
periods and is net of estimated forfeitures.
The following is a summary of activity in the Restricted Unit Plans:
Outstanding September 30, 2006
Granted
Forfeited
Vested
Outstanding September 29, 2007
Granted
Forfeited
Vested
Outstanding September 27, 2008
Granted
Forfeited
Vested
Outstanding September 26, 2009
Weighted Average
Grant Date Fair
Value Per Unit
$29.28
44.51
(30.06)
(28.34)
$28.85
35.19
(27.17)
(30.52)
$30.57
18.10
(31.92)
(27.81)
$28.89
Units
340,786
151,515
(47,023)
(62,188)
383,090
125,912
(11,359)
(51,128)
446,515
68,799
(28,382)
(71,637)
415,295
As of September 26, 2009, unrecognized compensation cost related to unvested restricted units awarded under
the Restricted Unit Plans amounted to $4,549. Compensation cost associated with the unvested awards is
expected to be recognized over a weighted-average period of 1.7 years. Compensation expense for the Restricted
Unit Plans for years ended September 26, 2009, September 27, 2008 and September 29, 2007 was $2,396, $2,156
and $3,014, respectively.
Long-Term Incentive Plan. The Partnership has a non-qualified, unfunded long-term incentive plan for officers
and key employees (“LTIP-2”) which provides for payment, in the form of cash, for an award of equity-based
compensation at the end of a three-year performance period. The level of compensation earned under LTIP-2 is
based on the market performance of the Partnership’s Common Units on the basis of total return to Unitholders
(“TRU”) compared to the TRU of a predetermined peer group comprised of other publicly traded partnerships
(master limited partnerships), as approved by the Compensation Committee of the Board of Supervisors, over the
same three-year performance period. Compensation expense, which includes adjustments to previously
recognized compensation expense for current period changes in the fair value of unvested awards, for the years
ended September 26, 2009, September 27, 2008 and September 29, 2007 was $3,402, $1,859 and $5,977,
respectively. The cash payouts in fiscal 2009, fiscal 2008 and fiscal 2007, which related to the fiscal 2006, fiscal
2005 and fiscal 2004 awards, were $2,741, $2,720 and $1,215, respectively.
F-21
10. Compensation Deferral Plan
The Compensation Deferral Plan provided eligible employees of the Partnership the ability to defer receipt of all
or a portion of vested restricted units granted under a prior restricted unit award plan. These units were held in
trust on behalf of the individuals. During the second quarter of fiscal 2008, the remaining 292,682 Common
Units were distributed to the participants resulting in the satisfaction of the deferred compensation obligation of
$5,660, classified in partners’ capital and a corresponding reduction to common units held in trust, classified as a
contra-equity balance within partners’ capital.
11. Employee Benefit Plans
Defined Contribution Plan. The Partnership has an employee Retirement Savings and Investment Plan (the
“401(k) Plan”) covering most employees. Employer matching contributions relating to the 401(k) Plan are a
percentage of the participating employees’ elective contributions. The percentage of the Partnership’s contributions
are based on a sliding scale depending on the Partnership’s achievement of annual performance targets. These
contributions totaled $5,676, $1,190 and $5,426 for the years ended September 26, 2009, September 27, 2008 and
September 29, 2007, respectively.
Defined Pension and Retiree Health and Life Benefits Arrangements
Pension Benefits. The Partnership has a noncontribut ory defined benefit pension plan which was originally
designed to cover all eligible employees of the Partnership who met certain requirements as to age and length of
service. Effective January 1, 1998, the Partnership amended its defined benefit pension plan to provide benefits
under a cash balance formula as compared to a final average pay formula which was in effect prior to January 1,
1998. Effective January 1, 2000, participation in the defined benefit pension plan was limited to eligible existing
participants on that date with no new participants eligible to participate in the plan. On September 20, 2002, the
Board of Supervisors approved an amendment to the defined benefit pension plan whereby, effective January 1,
2003, future service credits ceased and eligible employees receive interest credits only toward their ultimate
retirement benefit.
Contributions, as needed, are made to a trust maintained by the Partnership. Contributions to the defined benefit
pension plan are made by the Partnership in accordance with the Employee Retirement Income Security Act of 1974
minimum funding standards plus additional amounts made at the discretion of the Partnership, which may be
determined from time to time. There were no minimum funding requirements for the defined benefit pension plan
for fiscal 2009, 2008 or 2007. In recent years, cash balance defined benefit pension plans have come under
increased scrutiny resulting in litigation regarding such plans sponsored by other companies. Partly in response to
these developments, the federal Pension Protection Act of 2006 (the “2006 Pension Act”) was enacted, and these
developments may result in further legislative changes impacting cash balance defined benefit pension plans in the
future. There can be no assurances that future legislative developments will not have an adverse effect on the
Partnership’s results of operations or cash flows.
Retiree Health and Life Benefits. The Partnership provides postretirement health care and life insurance benefits
for certain retired employees. Partnership employees hired prior to July 1993 are eligible for postretirement life
insurance benefits if they reach a specified retirement age while working for the Partnership. Partnership employees
hired prior to July 1993 and who retired prior to March 1998 are eligible for postretirement health care benefits if
they reached a specified retirement age while working for the Partnership. Effective January 1, 2000, the
Partnership terminated its postretirement health care benefit plan for all eligible employees retiring after March 1,
1998. All active employees who were eligible to receive health care benefits under the postretirement plan
subsequent to March 1, 1998, were provided an increase to their accumulated benefits under the cash balance
pension plan. The Partnership’s postretirement health care and life insurance benefit plans are unfunded. Effective
January 1, 2006, the Partnership changed its postretirement health care plan from a self-insured program to one that
is fully insured under which the Partnership pays a portion of the insurance premium on behalf of the eligible
F-22
participants.
The Partnership recognizes the funded status of pension and other postretirement benefit plans as an asset or
liability on the balance sheet and recognizes changes in the funded status in comprehensive income (loss) in the
year the changes occur. The Partnership uses the date of its consolidated financial statements as the
measurement date of plan assets and obligations.
At the end of fiscal 2007, the Partnership adopted a new accounting standard pertaining to employers’ accounting
for defined benefit pension and other postretirement benefit plans. The initial impact of adopting this standard
was to recognize in accumulated other comprehensive income (loss) unrecognized prior service costs or credits
and net actuarial gains or losses that were previously unrecognized. The following table summarizes the effect of
required changes in the additional minimum liability (“AML”) reported in accumulated other comprehensive loss
as of September 29, 2007 prior to the adoption of the new standard, as well as the initial impact of adoption. The
AML was eliminated during fiscal 2007, primarily as a result of employer contributions.
September 29, 2007
Prior to AML
adjustments and
adoption of new
accounting standard
AML adjustments
prior to
adoption of new
accounting standard
Adoption of
new accounting
standard
September 29, 2007
Post AML
adjustments and
adoption of new
accounting standard
Accrued pension liability
(asset)
Accrued postretirement
liability
Accumulated other
comprehensive loss
$
9,990
$
(63,510)
$
47,973
$
(5,547)
$
29,353
$
-
$
(4,928)
$
24,425
$
63,510
$
(63,510)
$
43,045
$
43,045
Projected Benefit Obligation, Fair Value of Plan Assets and Funded Status. The following tables provide a
reconciliation of the changes in the benefit obligations and the fair value of the plan assets for each of the years
ended September 26, 2009 and September 27, 2008 and a statement of the funded status for both years. Under the
Partnership’s defined benefit pension plan, the accumulated benefit obligation and the projected benefit obligation
are the same.
F-23
Reconciliation of benefit obligations:
Benefit obligation at beginning of year
Service cost
Interest cost
Actuarial (gain) loss
Settlement payments
Benefits paid
Benefit obligation at end of year
Reconciliation of fair value of plan assets:
Fair value of plan assets at beginning of year
Actual return on plan assets
Employer contributions
Settlement payments
Benefits paid
Fair value of plan assets at end of year
Funded status:
Funded status at end of year
Amounts recognized in consolidated balance
sheets consist of:
Pension (liability) asset
Accrued benefit liability
Net amount recognized at end of year
Less: Current portion
Non-current benefit liability
Pension Benefits
2009
2008
Retiree Health and Life
Benefits
2009
2008
$
$
$
$
135,195
-
9,488
26,888
(6,130)
(8,254)
157,187
135,327
19,112
-
(6,130)
(8,254)
140,055
$
$
158,317
-
8,749
(16,904)
(6,653)
(8,314)
135,195
163,864
(13,570)
-
(6,653)
(8,314)
135,327
$
$
$
$
19,076
5
1,381
2,409
-
(1,744)
21,127
24,426
8
1,399
(4,954)
-
(1,803)
19,076
$
$
-
$
-
1,744
-
(1,744)
$
-
-
$
-
1,803
-
(1,803)
-
$
$
(17,132)
$
132
$
(21,127)
$
(19,076)
$
$
$
(17,132)
-
(17,132)
-
(17,132)
$
$
$
132
-
132
-
132
$
-
(21,127)
(21,127)
1,748
(19,379)
$
$
$
-
(19,076)
(19,076)
1,923
(17,153)
$
$
Amounts not yet recognized in net periodic benefit cost and
included in accumulated other comprehensive income (loss):
Actuarial net (loss) gain
Prior service credits
Net amount recognized in accumulated other comprehensive (loss)
income
$
(63,278)
-
$
(50,345)
-
$
2,842
3,338
$
5,563
3,826
$
(63,278)
$
(50,345)
$
6,180
$
9,389
The amounts in accumulated other comprehensive loss as of September 26, 2009 that are expected to be
recognized as components of net periodic benefit costs during the next fiscal year are $5,374 and ($555) for
pension and postretirement benefits, respectively.
Plan Asset Allocation. The following table presents the actual allocation of assets held in trust as of September
26, 2009 and September 27, 2008:
Fixed income securities - long-term bonds
Equity securities - domestic and international
2009
92%
8%
92%
2008
81%
19%
100%
The Partnership’s investment policies and strategies, as set forth in the Investment Management Policy and
Guidelines, are monitored by a Benefits Committee comprised of five members of management. During fiscal 2007,
the Benefits Committee proposed and the Board of Supervisors approved contributions to the plan in order to
F-24
improve the funded status of the accumulated benefit obligation and to change the plan’s asset allocation to reduce
investment risk and more closely match the asset mix to the future cash requirements of the plan. The
implementation of this strategy resulted in a $25,000 voluntary contribution in fiscal 2007, and a change in the asset
allocation to reflect a greater concentration of fixed income securities. The fixed income portion is invested in a
combination of long-term U.S. government bonds and intermediate-term corporate bonds with a strategy to match
the actuarially estimated duration of the plan’s projected benefit obligations. The target asset mix is as follows: (i)
fixed income securities portion of the portfolio should range between 75% and 95%; and (ii) equity securities
portion of the portfolio should range between 5% and 25%.
Projected Contributions and Benefit Payments. There are no projected minimum funding requirements under
the Partnership’s defined benefit pension plan for fiscal 2010. Estimated future benefit payments for both pension
and retiree health and life benefits are as follows:
Fiscal Year
2010
2011
2112
2013
2014
2015 through 2019
Pension
Benefits
$
19,896
13,380
13,810
12,720
12,986
54,113
Retiree
Health and
Life
Benefits
$
1,748
1,690
1,635
1,562
1,489
6,137
Effect on Operations. The following table provides the components of net periodic benefit costs included in
operating expenses for the years ended September 26, 2009, September 27, 2008 and September 29, 2007:
Pension Benefits
2008
2007
2009
Retiree Health and Life Benefits
2009
2007
2008
Service cost
Interest cost
Expected return on plan assets
Amortization of prior service credit
Settlement charge
Recognized net actuarial loss
Net periodic benefit costs
$
-
9,487
(9,205)
-
-
4,050
4,332
$
$
-
8,749
(9,082)
-
-
3,375
3,042
$
-
$
8,905
(10,317)
-
3,269
5,315
7,172
$
4
$
1,381
-
(490)
-
(312)
583
$
8
$
1,399
-
(490)
-
-
917
$
$
12
1,317
-
(597)
-
-
732
$
During fiscal 2007, lump sum pension benefit payments to either terminated or retiring individuals amounted to
$10,786, which exceeded the settlement threshold (combined service and interest costs of net periodic pension
cost) of $8,905 for fiscal 2007, and as a result, the Partnership was required to recognize a non-cash settlement
charge of $3,269 during the fourth quarter of fiscal 2007. The non-cash charge was required to accelerate
recognition of a portion of cumulative unrecognized losses in the defined benefit pension plan. During fiscal
2009 and 2008, the amount of the pension benefit obligation settled through lump sum payments did not exceed
the settlement threshold; therefore, a settlement charge was not required to be recognized in either of those fiscal
years.
F-25
Actuarial Assumptions. The assumptions used in the measurement of the Partnership’s benefit obligations as of
September 26, 2009 and September 27, 2008 are shown in the following table:
Pension Benefits
2009
2008
Retiree Health and
Life Benefits
2009
2008
Weighted-average discount rate
Average rate of compensation increase
5.125%
n/a
7.625%
n/a
5.125%
n/a
7.625%
n/a
The assumptions used in the measurement of net periodic pension benefit and postretirement benefit costs for the
years ended September 26, 2009, September 27, 2008 and September 29, 2007 are shown in the following table:
Pension Benefits
2008
2007
2009
Retiree Health and Life Benefits
2009
2007
2008
Weighted-average discount rate
Average rate of compensation
increase
Weighted-average expected long-
term rate of return on plan assets
Health care cost trend
7.625%
6.000%
5.500%
7.625%
6.000%
5.500%
n/a
n/a
n/a
n/a
n/a
n/a
7.390%
n/a
6.000%
n/a
8.000%
n/a
n/a
9.000%
n/a
9.500%
n/a
10.000%
The discount rate assumption takes into consideration current market expectations related to long-term interest
rates and the projected duration of the Partnership’s pension obligations based on a benchmark index with similar
characteristics as the expected cash flow requirements of the Partnership’s defined benefit pension plan over the
long-term. The expected long-term rate of return on plan assets assumption reflects estimated future performance
in the Partnership’s pension asset portfolio considering the investment mix of the pension asset portfolio and
historical asset performance. The expected return on plan assets is determined based on the expected long-term
rate of return on plan assets and the market-related value of plan assets. The market-related value of pension
plan assets is the fair value of the assets. Unrecognized actuarial gains and losses in excess of 10% of the greater
of the projected benefit obligation and the market-related value of plan assets are amortized over the expected
average remaining service period of active employees expected to receive benefits under the plan.
The 9.00% increase in health care costs assumed at September 26, 2009 is assumed to decrease gradually to 5.00%
in fiscal 2017 and to remain at that level thereafter. Increasing the assumed health care cost trend rates by 1.0% in
each year would increase the Partnership’s benefit obligation as of September 26, 2009 by approximately $432 and
the aggregate of service and interest components of net periodic postretirement benefit expense for the year ended
September 26, 2009 by approximately $28. Decreasing the assumed health care cost trend rates by 1.0% in each
year would decrease the Partnership’s benefit obligation as of September 26, 2009 by approximately $390 and the
aggregate of service and interest components of net periodic postretirement benefit expense for the year ended
September 26, 2009 by approximately $26. The Partnership has concluded that the prescription drug benefits within
the retiree medical plan do not entitle the Partnership to an available Medicare subsidy.
F-26
12. Financial Instruments
Cash and Cash Equivalents. The fair value of cash and cash equivalents is not materially different from their
carrying amount because of the short-term maturity of these instruments.
Derivative Instruments and Hedging Activities. The notional amount of the Partnership’s outstanding
derivative instruments includes the following (gallons in thousands):
Transaction Type
Commodity Options
Commodity Futures
As of
September 26,
2009
September 27,
2008
6,467
15,330
6,246
-
The following summarizes the gross fair value of the Partnership’s derivative instruments and their location in
the consolidated balance sheet as of September 26, 2009 and September 27, 2008, respectively:
Asset Derivatives
Derivatives not designated as
hedging instruments:
Commodity options
As of September 26, 2009
Location
Fair Value
As of September 27, 2008
Location
Fair Value
Other current assets
Other assets
$
6,398
241
Other current assets
Other assets
$
5,048
-
Commodity futures
Other current assets
Other assets
2,845
248
9,732
$
Other current assets
Other assets
-
-
5,048
$
Liability Derivatives
Derivatives designated as hedging
instruments:
Interest rate swaps
Derivatives not designated as
hedging instruments:
Commodity options
Location
Fair Value
Location
Fair Value
Other current liabilities
Other liabilities
$
$
3,351
840
4,191
Other current liabilities
Other liabilities
$
$
2,441
759
3,200
Other current liabilities
Other liabilities
$
4,060
175
Other current liabilities
Other liabilities
494
$
-
Commodity futures
Other current liabilities
784
5,019
$
Other current liabilities
-
$
494
As of September 26, 2009, the Partnership’s outstanding commodity-related derivatives mature between fiscal
2010 and fiscal 2011, and have a weighted average maturity of approximately 7 months. As of September 27,
2008, the Partnership’s outstanding commodity-related derivatives mature between fiscal 2009 and fiscal 2010,
and have a weighted average maturity of approximately 6 months.
F-27
The effect of the Partnership’s derivative instruments on the consolidated statement of operations for the years
ended September 27, 2009, September 27, 2008 and September 29, 2007 are as follows:
Derivatives in Cash Flow Hedging Relationships:
Year ended 9/26/2009
Interest rate swap
Amount of Gains
(Losses) Recognized in
OCI (Effective
Portion)
Gains (Losses) Reclassified from
Accumulated OCI into Income
(Effective Portion)
Location
Amount
$
(991)
Interest expense
$
-
Year ended 9/27/2008
Interest rate swap
Forwards
Year ended 9/29/2007
Interest rate swap
Forwards
Futures
$
$
(2,916)
-
(2,916)
$
$
(1,465)
1,292
-
(173)
Interest expense
Cost of products sold
Interest expense
Cost of products sold
Cost of products sold
-
$
1,377
1,377
$
-
$
(2,961)
994
(1,967)
$
Derivatives Not Designated as Hedging Instruments:
Year ended 9/26/2009
Options
Futures
Year ended 9/27/2008
Options
Futures
Year ended 9/29/2007
Options
Futures
Location of Gains
(Losses) Recognized in
Income
Amount of Unrealized Gains (Losses)
Recognized in Income
Cost of products sold
Cost of products sold
$ (589)
2,302
$ 1,713
Cost of products sold
Cost of products sold
$ 2,011
(247)
$ 1,764
Cost of products sold
Cost of products sold
$ (2,599)
(4,956)
$ (7,555)
Credit Risk. The Partnership’s principal customers are resi dential and commercial end users of propane and
fuel oil and refined fuels served by approximately 300 locations in 30 states. No single customer accounted for
more than 10% of revenues during fiscal 2009, 2008 or 2007 and no concentration of receivables exists as of
September 26, 2009 or September 27, 2008. During fiscal 2009, 2008 and 2007, three suppliers provided
approximately 40%, 35% and 34%, respectively, of the Partnership’s total propane supply. The Partnership believes
that, if supplies from any of these three suppliers were interrupted, it would be able to secure adequate propane
supplies from other sources without a material disruption of its operations.
Exchange traded futures and options contracts are traded on and guaranteed by the New York Mercantile
Exchange (the “NYMEX”) and as a result, have minimal credit risk. Futures contracts traded with brokers of the
NYMEX require daily cash settlements in margin accounts. The Partnership is subject to credit risk with
forward and option contracts entered into with various third parties to the extent the counterparties do not
perform. The Partnership evaluates the financial condition of each counterparty with which it conducts business
and establishes credit limits to reduce exposure to credit risk based on non-performance. The Partnership does
not require collateral to support the contracts.
F-28
Bank Debt and Senior Notes. The fair value of the Revolving Credit Facility approximates the carrying value
since the interest rates are periodically adjusted to reflect market conditions. Based upon quoted market prices,
the fair value of the Partnership’s 6.875% Senior Notes was $248,125 as of September 26, 2009.
13. Commitments and Contingencies
Commitments. The Partnership leases certain property, plant and equipment, including portions of the
Partnership’s vehicle fleet, for various periods under noncancelable leases. Rental expense under operating leases
was $17,254, $17,739 and $19,611 for the years ended September 26, 2009, September 27, 2008 and September 29,
2007, respectively.
Future minimum rental commitments under noncancelable operating lease agreements as of September 26, 2009 are
as follows:
Fiscal Year
2010
2011
2012
2013
2014
2015 and thereafter
Contingencies.
Minimum
Lease
Payments
$ 14,297
11,461
8,643
6,791
5,522
4,223
Self Insurance. As discussed in Note 2, the Partnership is self-insured for general and product, workers’
compensation and automobile liabilities up to predetermined amounts above which third party insurance applies. At
September 26, 2009 and September 27, 2008, the Partnership had accrued liabilities of $52,248 and $73,033,
respectively, representing the total estimated losses under these self-insurance programs. The Partnership is also
involved in various legal actions which have arisen in the normal course of business, including those relating to
commercial transactions and product liability. Management believes, based on the advice of legal counsel, that the
ultimate resolution of these matters will not have a material adverse effect on the Partnership’s financial position or
future results of operations, after considering its self-insurance liability for known and unasserted self-insurance
claims, as well as existing insurance policies in force. For the portion of the estimated liability that exceeds
insurance deductibles, the Partnership records an asset within other assets (or prepaid expenses and other current
assets, as applicable) related to the amount of the liability expected to be covered by insurance which amounted
to $14,812 and $38,825 as of September 26, 2009 and September 27, 2008, respectively.
During the first quarter of fiscal 2009, the Partnership agreed to settle a litigation involving alleged product
liability for approximately $30,000. The settlement was covered by insurance above the level of the Partnership’s
deductible. As a result of this settlement, in which the Partnership denied any liability, the Partnership increased
the portion of its estimated self-insurance liability that exceeded the insurance deductible and established a
corresponding asset of $30,000 as of September 27, 2008 to accrue for the settlement and subsequent
reimbursement from the Partnership’s third party insurance carrier. During fiscal 2009, the Partnership fully paid
the $30,000 to the claimants in this matter and was reimbursed for the same amount from the Partnership’s third
party insurance carrier.
Legal Matters. Following the Operating Partnership’s 1999 acquisition of the propane assets of SCANA
Corporation (“SCANA”), Heritage Propane Partners, L.P. had brought an action against SCANA for breach of
contract and fraud and against the Operating Partnership for tortious interference with contract and tortious
interference with prospective contract. On October 21, 2004, the jury returned a unanimous verdict in favor of
the Operating Partnership on all claims, but against SCANA. After the jury returned the verdict against SCANA,
F-29
the Operating Partnership filed a cross-claim against SCANA for indemnification, seeking to recover defense
costs. On November 2, 2006, SCANA and the Operating Partnership reached a settlement agreement wherein
the Operating Partnership received $2,000 as a reimbursement of defense costs incurred as a result of the lawsuit.
The $2,000 was recorded as a reduction to general and administrative expenses during the first quarter of fiscal
2007.
14. Guarantees
The Partnership has residual value guarantees associated with certain of its operating leases, related primarily to
transportation equipment, with remaining lease periods scheduled to expire periodically through fiscal 2016.
Upon completion of the lease period, the Partnership guarantees that the fair value of the equipment will equal or
exceed the guaranteed amount, or the Partnership will pay the lessor the difference. Although the fair value of
equipment at the end of its lease term has historically exceeded the guaranteed amounts, the maximum potential
amount of aggregate future payments the Partnership could be required to make under these leasing
arrangements, assuming the equipment is deemed worthless at the end of the lease term, is approximately
$18,337. The fair value of residual value guarantees for outstanding operating leases was de minimis as of
September 26, 2009 and September 27, 2008.
15. Public Offerings
On August 10, 2009, the Partnership sold 2,200,000 Common Units in a public offering at a price of $41.50 per
Common Unit realizing proceeds of $86,700, net of underwriting commissions and other offering expenses. On
August 24, 2009, following the underwriters’ partial exercise of their over-allotment option, the Partnership sold
an additional 230,934 Common Units at $41.50 per Common Unit, generating additional net proceeds of $9,180.
The aggregate net proceeds of $95,880, along with cash on hand, were used to fund the purchase of $175,000
aggregate principal amount of 2003 Senior Notes pursuant to a cash tender offer. These transactions increased
the total number of Common Units outstanding by 2,430,934 to 35,227,954.
16. Discontinued Operations and Disposition
The Partnership continuously evaluates its existing operations to identify opportunities to optimize the return on
assets employed and selectively divests operations in slower growing or non-strategic markets and seeks to
reinvest in markets that are considered to present more opportunities for growth. In line with that strategy, on
October 2, 2007, the Operating Partnership completed the sale of its Tirzah, South Carolina underground granite
propane storage cavern, and associated 62-mile pipeline, for $53,715 in cash, after taking into account certain
adjustments. The 57.5 million gallon underground storage cavern is connected to the Dixie Pipeline and provides
propane storage for the eastern United States. As part of the agreement, the Operating Partnership entered into a
long-term storage arrangement, not to exceed 7 million propane gallons, with the purchaser of the cavern that
will enable the Operating Partnership to continue to meet the needs of its retail operations, consistent with past
practices. As a result of this sale, a gain of $43,707 was reported as a gain from the disposal of discontinued
operations in the Partnership’s results for the first quarter of fiscal 2008. The results of operations from the
Tirzah facilities in the comparative prior year periods have been reclassified to discontinued operations on the
consolidated statements of operations for the fiscal year ended September 29, 2007.
During the first quarter of fiscal 2007, in a non-cash transaction, the Partnership completed a transaction in
which it disposed of nine customer service centers considered to be non-strategic in exchange for three customer
service centers of another company located in Alaska. The Partnership reported a $1,002 gain within
discontinued operations in the first quarter of fiscal 2007 for the amount by which the fair value of assets
relinquished exceeded the carrying value of the assets relinquished. During the second half of fiscal 2007, the
Partnership sold three customer service centers for net cash proceeds of $1,284 and reported a gain of $885 on
disposal of discontinued operations. Prior period results of operations attributable to these customer service
centers were not significant and, as such, have not been reclassified as discontinued operations.
F-30
17. Segment Information
The Partnership manages and evaluates its operations in five operating segments, three of which are reportable
segments: Propane, Fuel Oil and Refined Fuels and Natural Gas and Electricity. The chief operating decision
maker evaluates performance of the operating segments using a number of performance measures, including
gross margins and income before interest expense and provision for income taxes (operating profit). Costs
excluded from these profit measures are captured in Corporate and include corporate overhead expenses not
allocated to the operating segments. Unallocated corporate overhead expenses include all costs of back office
support functions that are reported as general and administrative expenses within the consolidated statements of
operations. In addition, certain costs associated with field operations support that are reported in operating
expenses within the consolidated statements of operations, including purchasing, training and safety, are not
allocated to the individual operating segments. Thus, operating profit for each operating segment includes only
the costs that are directly attributable to the operations of the individual segment. The accounting policies of the
operating segments are the same as those described in the summary of significant accounting policies in Note 2.
The propane segment is primarily engaged in the retail distribution of propane to residential, commercial,
industrial and agricultural customers and, to a lesser extent, wholesale distribution to large industrial end users.
In the residential and commercial markets, propane is used primarily for space heating, water heating, cooking
and clothes drying. Industrial customers use propane generally as a motor fuel burned in internal combustion
engines that power over-the-road vehicles, forklifts and stationary engines, to fire furnaces and as a cutting gas.
In the agricultural markets, propane is primarily used for tobacco curing, crop drying, poultry brooding and weed
control.
The fuel oil and refined fuels segment is primarily engaged in the retail distribution of fuel oil, diesel, kerosene
and gasoline to residential and commercial customers for use primarily as a source of heat in homes and
buildings.
The natural gas and electricity segment is engaged in the marketing of natural gas and electricity to residential
and commercial customers in the deregulated energy markets of New York and Pennsylvania. Under this
operating segment, the Partnership owns the relationship with the end consumer and has agreements with the
local distribution companies to deliver the natural gas or electricity from the Partnership’s suppliers to the
customer.
Activities in the all other category include the Partnership’s services business, which is primarily engaged in the
sale, installation and servicing of a wide variety of home comfort equipment, particularly in the areas of heating
and ventilation and activities from the Partnership’s HomeTown Hearth & Grill and Suburban Franchising
subsidiaries.
F-31
The following table presents certain data by reportable segment and provides a reconciliation of total operating
segment information to the corresponding consolidated amounts for the periods presented:
September 26,
2009
Year Ended
September 27,
2008
September 29,
2007
Revenues:
Propane
Fuel oil and refined fuels
Natural gas and electricity
All other
Total revenues
Income (loss) before interest expense and
provision for income taxes:
Propane
Fuel oil and refined fuels
Natural gas and electricity
All other
Corporate
Total income before interest expense and
provision for income taxes
Reconciliation to income from continuing
operations
Loss on debt extinguishment
Interest expense, net
Provision for income taxes
Depreciation and amortization:
Propane
Fuel oil and refined fuels
Natural gas and electricity
All other
Corporate
Income from continuing operations
$
Assets:
Propane
Fuel oil and refined fuels
Natural gas and electricity
All other
Corporate
Eliminations
Total assets
$
$
$
864,012
159,596
76,832
42,714
1,143,154
1,132,950
288,078
103,745
49,390
1,574,163
$
$
$
1,019,798
262,076
94,352
63,337
1,439,563
$
268,969
17,950
12,791
(16,346)
(72,749)
$
219,546
(2,825)
9,812
(16,044)
(60,361)
$
207,269
26,283
11,404
(26,335)
(54,025)
210,615
150,128
164,596
4,624
38,267
2,486
165,238
-
37,052
1,903
111,173
$
-
35,596
5,653
123,347
$
$
$
$
15,515
3,381
1,008
391
8,099
28,394
16,229
3,493
929
721
7,418
28,790
15,951
4,253
1,008
436
8,695
30,343
681,809
83,416
17,540
2,876
279,854
(87,981)
977,514
F-32
As of
September 26,
2009
September 27,
2008
$
$
746,281
70,548
23,658
4,075
279,132
(87,981)
1,035,713
$
$
Total depreciation and amortization
$
$
$
INDEX TO FINANCIAL STATEMENT SCHEDULE
SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES
Schedule II Valuation and Qualifying Accounts – Years Ended September 26, 2009,
September 27, 2008 and September 29, 2007...........................................................................
S-2
Page
S-1
SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
(in thousands)
SCHEDULE II
Balance at
Beginning
of Period
Charged
(credited) to Costs
and Expenses
Other
Additions
Deductions (a)
Balance
at End
of Period
Year Ended September 29, 2007
Allowance for doubtful accounts
Valuation allowance for deferred tax assets
$
5,530
47,733
$
4,331
(1,583)
$
-
-
$
(4,820)
(2,854)
$
5,041
43,296
Year Ended September 27, 2008
Allowance for doubtful accounts
Valuation allowance for deferred tax assets
$
5,041
43,296
$
9,166
6,930
$
-
-
$
(7,629)
(1,331)
$
6,578
48,895
Year Ended September 26, 2009
Allowance for doubtful accounts
Valuation allowance for deferred tax assets
$
6,578
48,895
$
3,284
(2,048)
-
$
-
$
(5,488)
(1,385)
$
4,374
45,462
(a) Represents amounts that did not impact earnings.
S-2
EXHIBIT 21.1
SUBSIDIARIES OF SUBURBAN PROPANE PARTNERS, L.P.
(as of November 25, 2009)
SUBURBAN LP HOLDING, INC. (Delaware)
SUBURBAN LP HOLDING, LLC (Delaware)
SUBURBAN PROPANE, L. P. (Delaware)
SUBURBAN SALES & SERVICE, INC. (Delaware)
GAS CONNECTION, LLC (Oregon) (d/b/a HomeTown Hearth & Grill)
SUBURBAN FRANCHISING, LLC (Nevada)
SUBURBAN ENERGY FINANCE CORP. (Delaware)
SUBURBAN PLUMBING NEW JERSEY, LLC (Delaware)
SUBURBAN HEATING OIL PARTNERS, LLC (Delaware) (d/b/a Suburban Propane)
AGWAY ENERGY SERVICES, LLC (Delaware)
SUBURBAN ALBANY PROPERTY, LLC (Delaware)
SUBURBAN BUTLER MONROE STREET PROPERTY, LLC (Delaware)
SUBURBAN CANTON ROUTE 11 PROPERTY, LLC (Delaware)
SUBURBAN CHAMBERSBURG FIFTH AVENUE PROPERTY, LLC (Delaware)
SUBURBAN ELLENBURG DEPOT PROPERTY, LLC (Delaware)
SUBURBAN GETTYSBURG PROPERTY, LLC (Delaware)
SUBURBAN LEWISTOWN PROPERTY, LLC (Delaware)
SUBURBAN MA SURPLUS PROPERTY, LLC (Delaware)
SUBURBAN MARCY PROPERTY, LLC (Delaware)
SUBURBAN MIDDLETOWN NORTH STREET PROPERTY, LLC (Delaware)
SUBURBAN NEW MILFORD SMITH STREET PROPERTY, LLC (Delaware)
SUBURBAN NJ PROPERTY ACQUISITIONS, LLC (Delaware)
SUBURBAN NJ SURPLUS PROPERTY, LLC (Delaware)
SUBURBAN NY PROPERTY ACQUISITIONS, LLC (Delaware)
SUBURBAN NY SURPLUS PROPERTY, LLC (Delaware)
SUBURBAN PA PROPERTY ACQUISITIONS, LLC (Delaware)
SUBURBAN PA SURPLUS PROPERTY, LLC (Delaware)
SUBURBAN ROCHESTER PROPERTY, LLC (Delaware)
SUBURBAN SODUS PROPERTY, LLC (Delaware)
SUBURBAN TEMPLE PROPERTY, LLC (Delaware)
SUBURBAN TOWANDA PROPERTY, LLC (Delaware)
SUBURBAN VERBANK PROPERTY, LLC (Delaware)
SUBURBAN VINELAND PROPERTY, LLC (Delaware)
SUBURBAN VT PROPERTY ACQUISITIONS, LLC (Delaware)
SUBURBAN WALTON PROPERTY, LLC (Delaware)
SUBURBAN WASHINGTON PROPERTY, LLC (Delaware)
EXHIBIT 23.1
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (No. 333-
109714) and Form S-8 (Nos. 333-72972, 333-138093 and 333-160768) of Suburban Propane Partners, L.P. of our
report dated November 25, 2009 relating to the financial statements, financial statement schedule, and the
effectiveness of internal control over financial reporting, which appears in this Form 10-K.
PricewaterhouseCoopers LLP
Florham Park, New Jersey
November 25, 2009
Certification of the President and Chief Executive Officer Pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002
EXHIBIT 31.1
I, Michael J. Dunn, Jr., certify that:
1.
I have reviewed this Annual Report on Form 10-K of Suburban Propane Partners, L.P.;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material
fact necessary to make the statements made, in light of the circumstances under which such statements were made, not
misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in
all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the
periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as
defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed
under our supervision, to ensure that material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is
being prepared;
b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be
designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and
the preparation of financial statements for external purposes in accordance with generally accepted accounting
principles;
c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our
conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by
this report based on such evaluation; and
d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during
the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that
has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial
reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over
financial reporting, to the registrant’s auditors and the audit committee of the registrant’s Board of Supervisors:
a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial
reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and
report financial information; and
b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the
registrant’s internal control over financial reporting.
November 25, 2009
By: /s/ MICHAEL J. DUNN, JR.
Michael J. Dunn, Jr.
President and Chief Executive Officer
Certification of the Chief Financial Officer
Pursuant to Section 302
of the Sarbanes-Oxley Act of 2002
EXHIBIT 31.2
I, Michael A. Stivala, certify that:
1.
I have reviewed this Annual Report on Form 10-K of Suburban Propane Partners, L.P.;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material
fact necessary to make the statements made, in light of the circumstances under which such statements were made, not
misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in
all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the
periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as
defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed
under our supervision, to ensure that material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is
being prepared;
b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be
designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and
the preparation of financial statements for external purposes in accordance with generally accepted accounting
principles;
c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our
conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by
this report based on such evaluation; and
d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during
the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that
has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial
reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over
financial reporting, to the registrant’s auditors and the audit committee of the registrant’s Board of Supervisors:
a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial
reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and
report financial information; and
b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the
registrant’s internal control over financial reporting.
November 25, 2009
By: /s/ MICHAEL A. STIVALA
Michael A. Stivala
Chief Financial Officer
Certification of the President and Chief Executive Officer Pursuant to
18 U.S.C. Section 1350,
as Adopted Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
EXHIBIT 32.1
In connection with the Annual Report of Suburban Propane Partners, L.P. (the “Partnership”) on Form 10-K for
the period ended September 26, 2009 as filed with the Securities and Exchange Commission on the date hereof
(the “Report”), I, Michael J. Dunn, Jr., President and Chief Executive Officer of the Partnership, certify, pursuant
to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:
(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act
of 1934; and
(2) The information contained in the Report fairly presents, in all material respects, the financial condition
and results of operations of the Partnership.
By: /s/ MICHAEL J. DUNN, JR.
Michael J. Dunn, Jr.
President and Chief Executive Officer
November 25, 2009
This certification shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934,
as amended (the “Exchange Act”), or incorporated by reference in any filing under the Securities Act of 1933, as
amended, or the Exchange Act, except as shall be expressly set forth by specific reference in such a filing.
Certification of the Chief Financial Officer
Pursuant to 18 U.S.C. Section 1350,
as Adopted Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
EXHIBIT 32.2
In connection with the Annual Report of Suburban Propane Partners, L.P. (the “Partnership”) on Form 10-K for
the period ended September 26, 2009 as filed with the Securities and Exchange Commission on the date hereof
(the “Report”), I, Michael A. Stivala, Chief Financial Officer of the Partnership, certify, pursuant to 18 U.S.C.
§ 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:
(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act
of 1934; and
(2) The information contained in the Report fairly presents, in all material respects, the financial condition
and results of operations of the Partnership.
By: /s/ MICHAEL A. STIVALA
Michael A. Stivala
Chief Financial Officer
November 25, 2009
This certification shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934,
as amended (the “Exchange Act”), or incorporated by reference in any filing under the Securities Act of 1933, as
amended, or the Exchange Act, except as shall be expressly set forth by specific reference in such a filing.
FIVE-YEAR PERFORMANCE GRAPH 1
EXHIBTI 99.1
The following graph compares the performance of our Common Units with the performance of the New York
Stock Exchange Index (the “NYSE Market Index”) and a peer group index for the period of the five fiscal years
commencing September 25, 2004. The graph assumes that at the beginning of the period, $100 was invested in
each of (1) our Common Units, (2) the NYSE Index, and (3) the peer group, and that all distributions or
dividends were reinvested.
We do not believe than any published industry or line-of-business index accurately reflects our business.
Accordingly, we have created a special peer group index consisting of three other propane-marketing companies
whose common units are publicly traded on the NYSE. Our peer group index includes the common units of the
following companies: Ferrellgas Partners, L.P., AmeriGas Partners, L.P., and Inergy, L.P.
COMPARISON OF 5-YEAR CUMULATIVE TOTAL RETURN
AMONG SUBURBAN PROPANE PARTNERS, L.P.,
NYSE MARKET INDEX AND PEER GROUP INDEX
200
175
150
125
100
75
50
25
S
R
A
L
L
O
D
0
2004
2005
2006
2007
2008
2009
SUBURBAN PROPANE PARTNERS, L.P.
PEER GROUP INDEX
NYSE MARKET INDEX
ASSUMES $100 INVESTED ON SEPT. 25, 2004
ASSUMES DIVIDEND REINVESTED
FISCAL YEAR ENDING SEPT. 25, 2009
1 The performance graph shall not be deemed incorporated by reference by any general statement incorporating by reference
this Annual Report on Form 10-K into any filing under the Securities Act of 1933, as amended or the Securities Exchange Act
of 1934, as amended, except to the extent that Suburban specifically incorporates this information by reference in such filing,
and shall not otherwise be deemed filed under such Acts.
Suburban Propane Partners, L.P.
One Suburban Plaza (cid:129) 240 Route 10 West
P.O. Box 206
Whippany, New Jersey 07981-0206
www.suburbanpropane.com