Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549FORM 10-K
[X] Annual Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934For the fiscal year ended September 29, 2007
[ ] Transition Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934Commission File Number: 1-14222
SUBURBAN PROPANE PARTNERS, L.P.
(Exact name of registrant as specified in its charter)
incorporation or organization)
Identification No.)240 Route 10 West
Whippany, NJ 07981
(973) 887-5300
(Address, including zip code, and telephone number,
including area code, of registrant’s principal executive offices)Securities registered pursuant to Section 12(b) of the Act:
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 Securities 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of ‘‘accelerated filer and large accelerated filer’’ in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer [X] Accelerated filer [ ] Non-accelerated filer [ ]
Indicate by check mark whether registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes [ ] No [X]
The aggregate market value as of March 30, 2007 of the registrant’s Common Units held by non-affiliates of the registrant, based on the reported closing price of such units on the New York Stock Exchange on such date ($44.00 per unit), was approximately $1,437,667,000.
Documents Incorporated by Reference: None Total number of pages (excluding Exhibits): 136
SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES
INDEX TO ANNUAL REPORT ON FORM 10-K
Table of ContentsDISCLOSURE 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:
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 Securities and Exchange Commission (‘‘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.
Table of ContentsPART I
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, ventilation and air conditioning (‘‘HVAC’’). We believe, based on LP/Gas Magazine dated February 2007, that we are the fourth largest retail marketer of propane in the United States, measured by retail gallons sold in the year 2006. As of September 29, 2007, we were serving the energy needs of approximately 1,000,000 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 432.5 million gallons of propane to retail customers and 104.5 million gallons of fuel oil and refined fuels during the year ended September 29, 2007. 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 newly-organized
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Table of Contentslimited liability company, wholly-owned (directly and indirectly) by the Partnership. Additionally, under the Partnership Agreement no incentive distribution rights are outstanding and no provisions for future incentive distribution rights are contained in the Partnership Agreement. The Common Units now 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 six retail stores in the northwest and northeast regions as of September 29, 2007. Suburban Franchising creates and develops propane related franchising business opportunities.
On December 23, 2003, we 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’’) pursuant to an asset purchase agreement dated November 10, 2003 (the ‘‘Agway Acquisition’’). With the Agway Acquisition, 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.
On November 21, 2003, Suburban Heating Oil Partners, LLC, a subsidiary of HomeTown Hearth & Grill, was formed to acquire and operate the fuel oil and refined fuels and HVAC businesses and assets of Agway Energy. In addition, Agway Energy Services, LLC, also a subsidiary of HomeTown Hearth & Grill, was formed to acquire and operate the natural gas and electricity marketing business of Agway Energy.
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. or 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 Securities and Exchange Commission (‘‘SEC’’). You may read and copy 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 29, 2007, 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, Reducing Our Cost Structure and Enhancing Our Customer Mix. We focus internally on improving the efficiency of our existing operations, managing
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Table of Contentsour cost structure and improving our customer mix. Through investments in our technology infrastructure, we continue to seek to improve operating efficiencies, particularly in the areas of routing, forecasting customer usage, inventory control and customer tracking. In furtherance of this strategy and to leverage our investments in technology, over the past two fiscal years (beginning at the end of fiscal 2005), we implemented plans to streamline our operating footprint and management structure, drive operating efficiencies, and refocus our HVAC activities on service offerings to support our existing customer base within our core operating segments. 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 intended to support our strategy of achieving sustainable profitable growth.
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. Specifically, in our propane segment, our residential customer base accounted for a higher percentage of our overall volumes sold in fiscal 2007 compared to prior years, primarily from the reduction of certain low margin commercial, industrial and agricultural customers. In our fuel oil and refined fuels segment, our decision in fiscal 2005 to begin to exit the majority of our lower margin diesel and gasoline businesses has resulted in a decrease in volumes sold in fiscal 2007 compared to prior years.
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 2007, 2006 or 2005 as we focused internally on driving efficiencies, reducing costs and integrating the operations of Agway Energy which were acquired in fiscal 2004. 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, on October 2, 2007 (subsequent to the end of fiscal 2007) we completed the sale of our Tirzah, South Carolina underground granite propane storage cavern, and associated 62-mile pipeline, for approximately $54.0 million in net proceeds which will be reinvested in the business.
Business Segments
We manage and evaluate our operations in six segments, four of which are reportable segments: Propane, Fuel Oil and Refined Fuels, Natural Gas and Electricity and HVAC. These business segments are described below. See Note 16 to the Consolidated Financial Statements included in this Annual Report for financial information about our business segments.
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Table of ContentsPropane
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:
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 29, 2007. Our operations are concentrated in the east and west coast regions of the United States, including Alaska. In fiscal 2007, we serviced approximately 791,000 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 91% of the propane gallons sold by us in fiscal 2007 were to retail customers: 44% to residential customers, 31% to commercial customers, 10% to industrial customers, 6% to agricultural customers and 9% to other retail users. The balance of approximately 9% of the propane gallons sold by us in fiscal 2007 was for risk management activities and wholesale customers. Sales to residential customers in fiscal 2007 accounted for approximately 70% 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 2007.
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
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Table of Contentssignificant 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 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 66 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 2008. During fiscal 2007, Targa Liquids Marketing and Trade (‘‘Targa’’) and Enterprise Products Operating L.P. (‘‘Enterprise’’) provided approximately 18% and 10%, respectively, of our total domestic propane purchases. Aside from these two suppliers, no single supplier provided more than 10% of our total domestic propane supply during fiscal 2007. 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 Enterprise were interrupted, we would be able to secure adequate propane supplies from other sources without a material disruption of our operations. Nevertheless, the cost of acquiring such propane might be higher and, at least on a short-term basis, margins could be affected. Approximately 94% of our total propane purchases were from domestic suppliers in fiscal 2007.
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 propane futures transactions on the New York Mercantile Exchange (‘‘NYMEX’’) and to forward and option contracts with various third parties to purchase and sell product 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 29, 2007, the majority of our storage capacity in California was leased to third parties. On October 2, 2007, we completed the sale of our Tirzah, South Carolina underground granite propane storage cavern, and associated 62-mile pipeline.
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Table of ContentsCompetition
According to the Energy Information Administration, propane accounts for approximately 4% 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 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 2005 Sales of Natural Gas Liquids and Liquefied Refinery Gases, as published by the American Petroleum Institute in March 2007, and LP/Gas Magazine dated February 2007, the ten largest retailers, including us, account for approximately 39% of the total retail sales of propane in the United States, and no single marketer has a greater than 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.
Fuel Oil and Refined Fuels
Product Distribution and Marketing
We market and distribute fuel oil, kerosene, diesel fuel and gasoline to approximately 97,000 residential and commercial customers in the northeast region of the United States. Sales of fuel oil and refined fuels for fiscal 2007 amounted to 104.5 million gallons. Approximately 60% of the refined fuel gallons sold by us in fiscal 2007 were to residential customers, principally for home heating, 8% were to commercial customers, 3% were to agricultural and 1% to other users. 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. Sales of diesel and gasoline accounted for the remaining 28% of total volumes sold in this segment during fiscal 2007.
Approximately 70% 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
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Table of Contentscustomers 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 2007.
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 more than 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 to market for transportation and volume discounts. We purchase fuel oil from nearly 23 suppliers at approximately 69 supply points. While fuel oil supply is more susceptible to longer periods of 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 2008.
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 HVAC segment 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 71,000 natural gas and electricity customers in New York and Pennsylvania. During fiscal 2007, we sold approximately 4.4 million dekatherms of natural gas and 510.3 million kilowatt hours of electricity through the natural gas and electricity segment. Approximately 90% of
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Table of Contentsour customers were residential households and the remainder were small commercial and industrial customers. New accounts are obtained through numerous marketing and advertising programs, including telemarketing and direct mail initiatives. Most local utility companies have established billing service arrangements whereby customers receive a single bill from the local utility company which includes distribution charges from the local utility company, as well as product charges for the amount of natural gas or electricity provided by AES and utilized by the customer. We have arrangements with several local utility companies that provide billing and collection services for a fee. Under these arrangements, we are paid by the local utility company for all or a portion of customer billings after a specified number of days following the customer billing with no further recourse to AES.
Supply of natural gas is arranged through annual supply agreements with major national wholesale suppliers. Pricing under the annual natural gas supply contracts is based on posted market prices at the time of delivery, and some contracts include a pricing formula that typically is based on prevailing market prices. The majority of our electricity requirements are purchased through the New York Independent System Operator (‘‘NYISO’’) under an annual supply agreement, as well as purchase arrangements through other national wholesale suppliers on the open market. Electricity pricing under the NYISO agreement is based on local market indices at the time of delivery. Competition is primarily with local utility companies, as well as other marketers of natural gas and electricity providing similar alternatives as AES.
HVAC
We sell, install and service all types of whole-house heating products, air cleaners, humidifiers, de-humidifiers, hearth products and space heaters to the customers of our propane, fuel oil, natural gas and electricity products. We also offer services such as duct cleaning, air balancing and energy audits to those customers. 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 HVAC providers and contractors, as well as, to a lesser extent, other regional service providers. During the third quarter of fiscal 2006, we initiated plans to restructure our HVAC service offerings and eliminated certain stand-alone installation activities. See Note 6 to the consolidated financial statements in this Annual Report. The focus of our ongoing service offerings will be 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.
All Other
Activities from our HomeTown Hearth & Grill and Suburban Franchising subsidiaries comprise the all other business caption.
Seasonality
The retail propane and fuel oil distribution businesses, as well as the natural gas marketing business, are seasonal because of the primary use of these fuels 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).
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
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Table of Contentsrely 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 use.
Trademarks and Tradenames
We utilize a variety of trademarks and tradenames owned by us, including ‘‘Suburban Propane,’’ ‘‘Gas Connection’’ and ‘‘HomeTown Hearth & Grill.’’ Additionally, in connection with the Agway Acquisition, we acquired 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 HVAC equipment. We regard our trademarks, tradenames and other proprietary rights as valuable assets and believe that they have significant value in the marketing of our products and services.
Government Regulation; Environmental and Safety Matters
We are subject to various federal, state and local environmental, health and safety laws and regulations. Generally, these laws impose limitations on the discharge of 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 fuel oil is considered a hazardous substance. 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.
With the Agway Acquisition, we acquired certain surplus 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 29, 2007, we had accrued environmental liabilities of $2.6 million representing the total estimated future liability for remediation and monitoring. For the portion of the estimated environmental liability that is recoverable under state environmental reimbursement funds, we record an asset within other assets related to the amount of the liability expected to be reimbursed by state agencies, which amounted to $0.1 million as of September 29, 2007.
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
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Table of Contentsbecomes 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 operate. 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 new regulations under 6 CFR Part 27 Chemical Facility Anti-Terrorism Standards. Our facilities are registered with the DHS and are proceeding through the screening process. 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 additional material liabilities to comply with the DHS regulations.
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.
Employees
As of September 29, 2007, we had 3,144 full time employees, of whom 416 were engaged in general and administrative activities (including fleet maintenance), 43 were engaged in transportation and product supply activities and 2,685 were customer service center employees. As of September 29, 2007, 91 of our employees were represented by 8 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.
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Table of ContentsYou 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 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:
Our Partnership Agreement gives our Board of Supervisors broad discretion in establishing cash reserves for, among other things, the proper conduct of our business. These cash reserves will affect the amount of cash available for distributions.
We have substantial indebtedness. Our debt agreements may limit our ability to make distributions to Unitholders, as well as our financial flexibility.
As of September 29, 2007, we had total outstanding borrowings of $550.0 million, including $425.0 million of senior notes issued by the Partnership and our wholly-owned subsidiary, Suburban Energy Finance Corporation, and $125.0 million of borrowings 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. 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 incur additional debt to finance acquisitions or for general business purposes, which 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.
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Table of ContentsIt 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 acquiror from conducting a solicitation of proxies to elect the acquiror’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:
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
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Table of Contentsaddition, 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 Common Unitholders that existed prior to the new issuance.
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 6% warmer than normal for the year ended September 29, 2007 compared to 11% warmer than normal temperatures in fiscal 2006 and 6% warmer than normal temperatures in fiscal 2005, as reported by the National Oceanic and Atmospheric Administration (‘‘NOAA’’). Furthermore, variations in weather in one or more regions in which we operate can significantly affect the total volume of propane, fuel oil and other refined fuels and natural gas we sell and, consequently, our results of operations. Variations in the weather in the northeast, where we have a greater concentration of 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 hedge certain 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
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Table of Contentsoverall 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 distributors to those offering delivery only. Generally, our existing fuel oil customers, unlike our existing propane customers, own their own tanks. As a result, the competition for these customers is more intense than in our propane business, where our existing customers seeking to switch distributors may face additional transition costs and delays.
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 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.
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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Table of ContentsThe risk of terrorism and political unrest and the current hostilities in the Middle East 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 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 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 material costs or liabilities 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, nor that all legal matters that arise will be covered by our insurance programs.
If we are unable to make acquisitions on economically acceptable terms or effectively integrate such acquisitions into our operations, our financial performance may be adversely affected.
The retail propane and fuel oil industries are mature. We foresee only limited growth in total retail demand for propane and flat to moderately declining retail demand for fuel oil. With respect to
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Table of Contentsour retail propane business, because of the long-standing customer relationships that are typical in our industry, the inconvenience of switching tanks and suppliers and propane’s higher cost relative to other energy sources, such as natural gas, it may be difficult for us to acquire new 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.
Tax Risks to Unitholders
Our tax treatment depends on our status as a partnership for federal income tax purposes. The 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. 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 35% federal rate) and likely would be required to pay state income tax at varying rates. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our Unitholders would be substantially reduced. Therefore, our treatment as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our Unitholders, likely causing a substantial reduction in the value of 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
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Table of Contentsunrelated 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.
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.
Tax shelter registration could increase the risk of a potential audit by the IRS.
We registered as a ‘‘tax shelter’’ under the law in effect at the time of our initial public offering and were assigned tax shelter registration number 96080000050. The issuance of a tax shelter registration number to us does not indicate that a Common Unit investment in us or the claimed tax benefits have been reviewed, examined or approved by the IRS.
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.
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Table of ContentsThere 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.
Unitholders may have negative tax consequences if we default on our debt or sell assets.
If we default on any of our debt obligations, our lenders will have the right to sue us for non-payment. This could cause an investment loss and negative tax consequences for Unitholders through the realization of taxable income by Unitholders without a corresponding cash distribution. Likewise, if we were to dispose of assets and realize a taxable gain while there is substantial debt outstanding and proceeds of the sale were applied to the debt, Unitholders could have increased taxable income without a corresponding cash distribution.
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in 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 capital and profits 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.
None.
As of September 29, 2007, 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. Effective October 2, 2007, we sold our 60 million gallon underground propane storage cavern in Tirzah, South Carolina. Additionally, we own our principal executive offices located in Whippany, New Jersey.
The transportation of propane requires specialized equipment. The trucks and railroad tank cars utilized for this purpose carry specialized steel tanks that maintain the propane in a liquefied state. As of September 29, 2007, we had a fleet of 11 transport truck tractors, of which we owned two, and 21 railroad tank cars, of which we owned one. In addition, as of September 29, 2007 we had 991 bobtail and rack trucks, of which we owned approximately 36%, 187 fuel oil tankwagons, of which we owned approximately 68%, and 1,333 other delivery and service vehicles, of which we owned approximately 52%. We lease the vehicles we do not own. As of September 29, 2007, we also owned approximately 831,401 customer propane storage tanks with typical capacities of 100 to 500 gallons, 173,835 customer propane storage tanks with typical capacities of over 500 gallons and 242,678 portable propane cylinders with typical capacities of five to ten gallons.
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
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Table of Contentscontinue 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 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 $50.3 million at September 29, 2007), 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 to be covered by insurance (which was approximately $13.9 million at September 29, 2007).
None.
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Table of ContentsPART II
(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 20, 2007, there were 785 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.
Declared per Common UnitWe 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.
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Table of ContentsThe 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.
2007
2006 (a)
2005
2004 (b)
2003 Statement of Operations Data21
Table of Contents
2007
2006 (a)
2005
2004 (b)
2003 EBITDA and Adjusted EBITDA (j)
growth (k)22
Table of Contents (h) On October 2, 2007, we completed the sale of our Tirzah, South Carolina underground granite propane storage cavern, and associated 62-mile pipeline, for approximately $54.0 million in net proceeds (the ‘‘Tirzah Sale’’). The 57.5 million gallon underground storage cavern is connected to the Dixie Pipeline and provides propane storage for the eastern United States. As a result of this sale, a gain of approximately $40.0 million will be reported as a gain from the disposal of discontinued operations in our results for the first quarter of fiscal 2008. The results of operations from the Tirzah facilities have been reported within discontinued operations. Because the transaction closed subsequent to the end of fiscal 2007, our cash on hand at September 29, 2007 does not include the net proceeds of approximately $54.0 million. (i) Computations of earnings per Common Unit for the year ended September 29, 2007 were performed in accordance with SFAS No. 128 ‘‘Earnings per Share’’ (‘‘SFAS 128’’) by dividing net income by the weighted average number of outstanding Common Units. For fiscal 2006, earnings per Common Unit were performed in accordance with Emerging Issues Task Force consensus 03-6 ‘‘Participating Securities and the Two-Class Method Under FAS 128’’ (‘‘EITF 03-6’’), when applicable. EITF 03-6 requires, among other things, the use of the two-class method of computing earnings per unit when participating securities exist. 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 of computing income per Common Unit under EITF 03-6 is no longer applicable.The requirements of EITF 03-6, which we adopted at the end of fiscal 2004, 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, nor did it have any impact on income per Common Unit for the years ended September 25, 2004 or September 27, 2003. Application of the two-class method under EITF 03-6 had a negative impact on income per Common Unit of $0.07 for the year ended September 30, 2006 compared to the computation under SFAS No. 128. Basic net income (loss) per Common Unit for the years ended September 24, 2005, September 25, 2004 and September 27, 2003 was computed under SFAS 128 by dividing net income (loss), after deducting our General Partner’s interest, by the weighted average number of outstanding Common Units. Diluted net income (loss) per Common Unit for these same periods was computed by dividing net income (loss), after deducting our General Partner’s interest, by the weighted average number of outstanding Common Units and unvested restricted units under our 2000 Restricted Unit Plan. For purposes of the computation of income per Common Unit for the year ended September 30, 2007, earnings that would have been allocated to the General Partner for the period prior to the GP Exchange Transaction were not significant.
(j) EBITDA represents net income before deducting interest expense, income taxes, depreciation and amortization. Our management uses EBITDA as a measure of liquidity and we are including 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 the term Adjusted EBITDA to reflect the presentation of EBITDA for the year ended September 24, 2005 exclusive of the impact of the non-cash charge for loss on debt extinguishment in the amount of $36.2 million. 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 or Adjusted EBITDA as a component in calculating our leverage and interest coverage ratios. EBITDA and Adjusted EBITDA are not23
Table of Contents recognized terms under generally accepted accounting principles (‘‘GAAP’’) and should not be considered as alternatives 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 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):
(k) 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.
2007
2006
2005
2004
2003 Net income (loss)24
The following is a discussion of our financial condition and results of operations, which should be read in conjunction with our historical consolidated financial statements and notes thereto included elsewhere in this Annual Report.
The following are factors that regularly affect our operating results and financial condition. In addition, our business is subject to the risks and uncertainties described in Item 1A of this Annual Report.
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 also purchase product on the open market. We attempt to reduce price risk by pricing product on a short-term basis. Our propane supply contracts typically provide for pricing based upon index formulas using the posted prices established at major supply points such as Mont Belvieu, Texas, or Conway, Kansas (plus transportation costs) at the time of delivery. In certain instances, and when market conditions are favorable as was the case in the fuel oil market during the first half of fiscal 2007, we are able to purchase product under our supply arrangements at a discount to the market.
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 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 may be 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.
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
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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 use.
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 futures and option contracts traded on the NYMEX, to purchase and sell propane and fuel oil at fixed prices in the future. The majority of the futures, forward and option agreements are used to hedge forecasted purchases of propane or fuel oil and are generally settled at expiration of the contract. Although we use derivative instruments to reduce the effect of price volatility associated with 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, through enforcement of our Hedging and Risk Management Policy and reported to our Audit Committee.
As a result of various market factors during the first half of fiscal 2007, particularly commodity price volatility during the first four months of the fiscal year, we experienced additional margin opportunities due to favorable pricing under certain supply arrangements and from our supply and risk management activities. These market conditions generated additional operating profit of approximately $14.7 million during the year ended September 29, 2007. However, supply and risk management transactions may not always result in increased product margins and there can be no assurance that these favorable market conditions will be present in the future in order to provide the additional margin opportunities realized during fiscal 2007. See Item 7A of this Annual Report.
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 GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We are also subject to risks and uncertainties that may cause actual results to differ from estimated results. Estimates are used when accounting for depreciation and amortization of long-lived assets, employee benefit plans, self-insurance and litigation reserves, environmental reserves, allowances for doubtful accounts, asset valuation assessments and valuation of derivative instruments. We base our estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known to us. Management has reviewed these critical accounting estimates and related disclosures with the Audit Committee of our Board of Supervisors. We believe that the following are our critical accounting estimates:
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,
26
maintenance and other service activities is recognized upon completion of the service. Revenue from HVAC 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, plus an amount for natural gas and electricity delivered but unbilled at the end of each accounting period.
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.
Pension and Other Postretirement Benefits. We estimate the rate of return on plan assets, the discount rate to estimate the present value of future benefit obligations and the 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.
Self-Insurance Reserves. Our accrued 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 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.
Environmental Reserves. We establish reserves for environmental exposures when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated based upon our evaluation of costs associated with environmental remediation and ongoing monitoring activities. Inherent uncertainties exist in such evaluations due to unknown conditions and changing laws and regulations. These liabilities are adjusted periodically as remediation efforts progress or as additional technical or legal information becomes available. Accrued environmental reserves are exclusive of claims against third parties, and an asset is established where contribution or reimbursement from such third parties, such as governmental agencies, has been agreed and we are reasonably assured of receiving such contribution or reimbursement. Environmental reserves are not discounted.
Goodwill Impairment Assessment. We assess the carrying value of goodwill at a reporting unit level, at least annually, based on an estimate of the fair value of each reporting unit. Fair value of the reporting unit is estimated using discounted cash flow analyses taking into consideration estimated cash flows in a ten-year projection period and a terminal value calculation at the end of the projection period.
Derivative Instruments and Hedging Activities. See Item 7A of this Annual Report for information about accounting for derivative instruments and hedging activities.
Executive Overview of Results of Operations and Financial Condition
During fiscal 2007, we took several steps to deliver increasing value to our Unitholders, streamline our cost structure and further strengthen our balance sheet. Through our efforts over the past two fiscal years to drive operating efficiencies, reduce costs and improve our customer mix, during
27
fiscal 2007 we reported our second consecutive year of record earnings. Net income for fiscal 2007 of $127.3 million, or $3.91 per Common Unit, increased $36.6 million compared to net income of $90.7 million, or $2.84 per Common Unit, in the prior year. EBITDA (as defined and reconciled below) increased $32.5 million, or 19.7%, to $197.8 million in fiscal 2007, compared to EBITDA of $165.3 million in fiscal 2006. Fiscal 2007 included 52 weeks of operations compared to 53 weeks in fiscal 2006.
From a cash flow perspective, despite the sustained period of high commodity prices, we continue to fund working capital requirements from cash on hand and have not borrowed under our working capital facility since April 2006. Additionally, during fiscal 2007 we made a voluntary contribution of $25.0 million to our pension plan from cash on hand in order to fully fund our accumulated benefit obligation which we believe will reduce, if not eliminate, future funding requirements. Even after this voluntary contribution, we ended fiscal 2007 in a strong cash position with approximately $96.6 million in cash on hand, an increase of $36.0 million, or 59.4%, compared to the end of fiscal 2006. On the strength of these earnings and improved cash flows, our Board of Supervisors increased the annualized distribution rate by $0.35 per Common Unit during fiscal 2007 to $3.00 per Common Unit, an increase of 13% compared to the annualized distribution rate at the end of fiscal 2006. Subsequent to the end of fiscal 2007, we also closed on the sale of our Tirzah, South Carolina underground propane storage facility and related 62-mile pipeline (the ‘‘Tirzah Sale’’) for net proceeds of $54.0 million, thus further increasing the cash on hand.
The most significant factor contributing to the growth in earnings was a $49.5 million, or 11.6%, decline in combined operating and general and administrative expenses (excluding certain items of a non-recurring nature in both fiscal years as described below) for fiscal 2007 compared to the prior year, despite a $7.0 million increase in variable compensation costs in line with higher earnings. Since our field and HVAC realignment process began at the end of fiscal 2005, we have eliminated nearly 1,000 positions and retired nearly 1,000 vehicles from our fleet, generating significant savings in our fixed cost structure for the foreseeable future.
In addition, our efforts to improve our customer mix through the strategic exit from certain lower margin business in both the propane and refined fuels segments contributed to the improved year-over-year operating results. Specifically, in the propane segment, we focused on higher margin residential customers and, in several instances, exited certain lower margin commercial, industrial and agricultural customers which accounted for a decrease in volumes sold of approximately 20.9 million gallons compared to the prior year. In the fuel oil and refined fuels segment, our decision to exit certain lower margin diesel and gasoline business resulted in a decrease in volumes sold of approximately 21.7 million gallons in fiscal 2007 compared to the prior year. Overall, retail propane volumes sold during fiscal 2007 decreased 34.3 million gallons, or 7.3%, to 432.5 million gallons compared to 466.8 million gallons in fiscal 2006. Sales of fuel oil and refined fuels decreased 41.1 million gallons, or 28.2%, to 104.5 million gallons in fiscal 2007 compared to 145.6 million gallons in fiscal 2006. Ongoing customer conservation in the sustained high energy price environment, combined with the impact of exiting lower margin business, has had the most significant negative impact on volumes, despite colder average temperatures compared to the prior year. Average temperatures in our service territories were 94% of normal for fiscal 2007 compared to 89% of normal temperatures in the prior year.
In the commodities market, average posted prices for both propane and fuel oil remained high relative to historical trends and, in particular, increased sharply towards the end of fiscal 2007. Average posted prices for propane increased 2.6% and average fuel oil prices decreased 1.2% during fiscal 2007 compared to the prior year. By the end of September 2007 the average posted prices for propane and fuel oil were 41% and 33% higher, respectively, compared to the average posted prices at the end of September 2006. The impact of lower volumes was offset to an extent by higher average margins from an improved customer mix, as well as from additional margin opportunities due to favorable pricing under certain supply arrangements and from hedging and risk management activities, particularly during the first half of fiscal 2007. We attribute approximately $14.7 million of the fiscal 2007 profitability to the favorable supply and market factors. However, supply and risk management
28
activities may not always result in increased product margins and there can be no assurance that the favorable market conditions will be present in the future in order to provide the additional margin contribution realized in fiscal 2007.
Net income and EBITDA for fiscal 2007 included (i) a non-cash pension settlement charge of $3.3 million to accelerate the recognition of actuarial losses in our defined benefit pension plan as a result of the level of lump sum retirement benefit payments made during fiscal 2007; (ii) severance charges of $1.5 million related to positions eliminated in fiscal 2007; (iii) a $2.0 million gain from the recovery of a substantial portion of legal fees associated with our 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 – deferred taxes of $3.8 million.
EBITDA and net income for fiscal 2006 were unfavorably impacted by $17.5 million as a result of certain significant items relating mainly to: (i) $6.1 million of restructuring charges primarily related to severance benefits associated with our field realignment and the restructuring of our HVAC business; (ii) incremental professional services fees of $5.0 million associated with the GP Exchange Transaction consummated on October 19, 2006; (iii) a non-cash pension settlement charge of $4.4 million; and (iv) a $2.0 million charge included within cost of products sold to reduce the carrying value of service inventory that will no longer be marketed by our customer service centers as a result of our reorganization.
As we look ahead to fiscal 2008, our anticipated cash requirements include: (i) maintenance and growth capital expenditures of approximately $25.0 million; (ii) approximately $37.0 million of interest and income tax payments; and, (iii) assuming distributions remain at the current level, approximately $98.1 million of distributions to Common Unitholders. Based on our current estimate of our cash position, availability under the Revolving Credit Agreement (unused borrowing capacity under the working capital facility of $124.0 million at September 29, 2007) and expected cash flow from operating activities, we expect to have sufficient funds to meet our current and future obligations.
Results of Operations
Fiscal Year 2007 Compared to Fiscal Year 2006
Fiscal 2007 included 52 weeks of operations compared to 53 weeks in the prior year, which has affected operating results for all categories discussed below.
Revenues
2007
2006
Decrease RevenuesTotal revenues decreased $217.6 million, or 13.1%, to $1,439.6 million for the year ended September 29, 2007 compared to $1,657.1 million for the year ended September 30, 2006, driven primarily by lower volumes in each of our operating segments, offset to an extent by the higher average selling prices. As reported by NOAA, average temperatures in our service territories were 6% warmer than normal for fiscal 2007 compared to 11% warmer than normal temperatures in fiscal 2006. Lower volumes, despite the colder average temperatures compared to the prior year, were attributed to ongoing customer conservation driven by high energy costs, our ongoing efforts to improve our customer mix by exiting certain lower margin accounts, as well as the impact of the additional week of operations in the prior year.
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Revenues from the distribution of propane and related activities of $1,019.8 million for the year ended September 29, 2007 decreased $61.8 million, or 5.7%, compared to $1,081.6 million in the prior year, primarily due to lower volumes, offset to an extent by higher average selling prices. Retail propane gallons sold in fiscal 2007 decreased 34.3 million gallons, or 7.3%, to 432.5 million gallons from 466.8 million gallons in the prior year. Propane volumes sold were negatively affected by customer conservation efforts, and our effort to focus on higher margin residential customers. Average propane selling prices increased 5.1% year-over-year as a result of higher commodity prices for propane and a more favorable customer mix. The average posted price of propane during fiscal 2007 increased 2.6% compared to the average posted prices in the prior year. Additionally, included within the propane segment are revenues from wholesale and risk management activities of $44.8 million for the year ended September 29, 2007, which decreased $29.6 million, or 39.8%, compared to the prior year primarily due to lower risk management activity in the continued high price environment.
Revenues from the distribution of fuel oil and refined fuels of $262.1 million for the year ended September 29, 2007 decreased $94.5 million, or 26.5%, from $356.5 million in the prior year. Fuel oil and refined fuels gallons sold in fiscal 2007 decreased 41.1 million gallons, or 28.2%, to 104.5 million gallons compared to 145.6 million gallons in the prior year. Lower volumes in our fuel oil and refined fuels segment were attributable primarily to our continued efforts to exit certain lower margin gasoline and low sulfur diesel businesses which resulted in an approximate decrease of 21.7 million gallons, or 53% of the total volume decline compared to the prior year. Average selling prices in our fuel oil and refined fuels segment increased 2.4% as a result of the decreased emphasis on lower priced gasoline and diesel businesses. The average posted price of fuel oil during fiscal 2007 decreased 1.2% compared to the average posted prices in the prior year, yet increased sharply during September 2007 compared to the prior year.
Revenues in our natural gas and electricity marketing segment decreased $27.7 million, or 22.7%, to $94.4 million in fiscal 2007 primarily from lower volumes and lower average selling prices for both natural gas and electricity. Revenues in our HVAC segment declined 35.2%, to $56.5 million during fiscal 2007 compared to $87.3 million in the prior year, primarily as a result of the decision during the third quarter of fiscal 2006 to reorganize the HVAC segment and to reduce the level of stand alone HVAC installation activities. The focus of our ongoing service offerings will be in support of our existing propane, refined fuels and natural gas and electricity segments, thus reducing overall HVAC segment revenues.
Cost of Products Sold
2007
2006
Decrease Cost of products soldThe 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 in each quarterly reporting
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period within cost of products sold. Cost of products sold is reported exclusive of any depreciation and amortization; these amounts are reported separately within the consolidated statements of operations.
Cost of products sold decreased $186.4 million, or 17.7%, to $865.4 million for the year ended September 29, 2007, compared to $1,051.8 million in the prior year. The decrease results primarily from the lower sales volumes described above, as well as the impact of various favorable market factors impacting our supply and risk management activities which provided incremental margin opportunities in fiscal 2007. We attribute approximately $14.7 million of the fiscal 2007 margins to these favorable market conditions that may not be present in the future. Additionally, cost of products sold for fiscal 2007 included a $7.6 million unrealized (non-cash) loss representing the net change in fair values of derivative instruments under SFAS No. 133, ‘‘Accounting for Derivative Instruments and Hedging Activities,’’ as amended (‘‘SFAS 133’’), compared to a $14.5 million unrealized (non-cash) gain in the prior year (see Item 7A of this Annual Report for information on our policies regarding the accounting for derivative instruments).
Cost of products sold associated with the distribution of propane and related activities of $573.3 million decreased $62.1 million, or 9.8%, compared to the prior year. Lower sales volumes resulted in a $41.3 million decrease in cost of products sold during fiscal 2007 compared to the prior year, partially offset by higher commodity prices which had an unfavorable impact of $0.7 million compared to the prior year. In addition, the impact of mark-to-market adjustments for derivative instruments under SFAS 133 resulted in a $3.8 million increase in cost of products sold as fiscal 2007 included a $1.9 million unrealized (non-cash) loss, compared to a $1.9 million unrealized (non-cash) gain in the prior year. Wholesale and risk management activities resulted in a $25.6 million decrease in cost of products sold compared to the prior year due to lower risk management activities.
Cost of products sold associated with our fuel oil and refined fuels segment of $194.2 million decreased $77.8 million, or 28.6%, compared to the prior year. Lower sales volumes and lower commodity prices resulted in a decrease in cost of products sold of $80.4 million and $15.8 million, respectively, during fiscal 2007 compared to the prior year. These declines were partially offset by the impact of mark-to-market adjustments for derivative instruments under SFAS 133, which resulted in a $18.3 million increase in cost of products sold as fiscal 2007 included a $5.7 million unrealized (non-cash) loss, compared to a $12.6 million unrealized (non-cash) gain in the prior year.
Cost of products sold in our natural gas and electricity segment of $77.1 million decreased $25.6 million, or 24.9%, compared to prior year primarily due to lower revenues.
Cost of products sold in our HVAC segment of $16.8 million decreased $19.1 million, or 53.2%, compared to prior year primarily due to lower revenues and a charge of $3.5 million in fiscal 2006 to reduce the carrying value of service inventory that is no longer actively marketed by our customer service centers.
For the year ended September 29, 2007, total cost of products sold represented 60.1% of revenues compared to 63.5% in the prior year, primarily as a result of an improved customer mix from our decision to exit certain lower margin customers in both the propane and fuel oil and refined fuels segments, as well as the impact of various favorable market factors impacting our supply and risk management activities and the lower HVAC activities.
Operating Expenses
2007
2006
Decrease Operating expensesAll 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.
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Operating expenses of $322.9 million for the year ended September 29, 2007 decreased $50.5 million, or 13.5%, compared to $373.3 million in the prior year, which included an additional week of operations. In fiscal 2007, we realized the full-year effect of the operating efficiencies, lower headcount and lower vehicle count resulting from our field and HVAC reorganizations that began at the end of the third quarter of fiscal 2005 and continued into the beginning of fiscal 2007. The most significant cost savings were experienced in payroll and benefit related expenses which declined $28.5 million, as well as a decrease of $7.1 million in vehicle expenditures and savings in other costs of $16.5 million to operate our customer service centers. These cost savings were offset to an extent by a $2.7 million increase in variable compensation resulting from the improved earnings in fiscal 2007 compared to the prior year. In addition, fiscal 2007 operating expenses include a non-cash pension settlement charge of $3.3 million, which was $1.1 million lower than the prior year charge of $4.4 million, in order to accelerate the recognition of a portion of unrecognized actuarial losses in our defined benefit pension plan as a result of the level of lump sum retirement benefit payments made during each of the respective fiscal years.
General and Administrative Expenses
2007
2006
Decrease General and administrative expensesAll costs of our back office support functions, including compensation and benefits for executives and other support functions, as well as other costs and expenses to maintain finance and accounting, treasury, legal, human resources, corporate development and the information systems functions are reported within general and administrative expenses in the consolidated statements of operations.
General and administrative expenses of $56.4 million for the year ended September 29, 2007 were $7.1 million, or 11.2%, lower compared to $63.6 million in fiscal 2006. The decrease was primarily attributable to a $5.0 million reduction in professional services fees incurred in the prior year associated with the GP Exchange Transaction consummated on October 19, 2006, as well as $4.4 million in higher costs incurred in the prior year associated with our field realignment effort. The reduction in professional services fees also includes a $2.0 million gain from our recovery of a substantial portion of legal fees associated with our successful defense of a matter following the 1999 acquisition of certain propane assets in North and South Carolina. These cost savings were offset to an extent by a $4.3 million increase in variable compensation resulting from the improved earnings in fiscal 2007 compared to the prior year.
Restructuring Charges and Severance Costs. For the year ended September 29, 2007, we recorded a charge of $1.5 million related to severance costs incurred associated with positions eliminated during fiscal 2007 unrelated to a specific plan of restructuring. For the year ended September 30, 2006, we recorded a restructuring charge of $6.1 million related primarily to severance costs incurred to effectuate our field realignment and HVAC restructuring initiatives during fiscal 2006.
Depreciation and Amortization
2007
2006
Decrease Depreciation and amortizationDepreciation and amortization expense for the year ended September 29, 2007 decreased $3.9 million, or 11.8%, compared to the prior year primarily as a result of lower amortization expense on intangible assets that have been fully amortized, coupled with lower depreciation from asset retirements. Fiscal 2006 depreciation and amortization expense included a $1.1 million asset impairment charge associated with our field realignment efforts, as well as the write-down of certain assets.
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Interest Expense, net
2007
2006
Decrease Interest expense, netNet interest expense decreased $5.1 million, or 12.5%, to $35.6 million in fiscal 2007. During fiscal 2007, there were no borrowings under our working capital facility as seasonal working capital needs have been funded through improved cash flow and cash on hand, resulting in lower interest expense. In the prior year period, average borrowings under our working capital facility amounted to $13.4 million with a peak borrowing level of $84.0 million. Additionally, as a result of increased cash on hand, interest income on invested cash has increased compared to the prior year, thus reducing net interest expense.
Discontinued Operations. During the first quarter of fiscal 2007, in a non-cash transaction, we completed a transaction in which 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 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. As part of our overall business strategy, we continually monitor and evaluate existing operations in order to identify opportunities to optimize return on assets by selectively divesting operations in slower growing or non-strategic markets. During fiscal 2007, we also sold three customer service centers for net cash proceeds of $1.3 million and recorded a gain on sale of $0.9 million which has been accounted for in accordance with SFAS 144.
On October 2, 2007, we completed the sale of our Tirzah, South Carolina underground granite propane storage cavern, and associated 62-mile pipeline, for approximately $54.0 million in net proceeds. 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, we entered into a long-term storage arrangement 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, a gain of approximately $40.0 million will be reported as a gain from the disposal of discontinued operations in our results for the first quarter of fiscal 2008. The results of operations from the Tirzah facilities have been reported within discontinued operations. Because the transaction closed subsequent to the end of fiscal 2007, our cash on hand at September 29, 2007 does not include the approximate $54.0 million of net proceeds from the sale.
Net Income and EBITDA. We reported net income of $127.3 million, or $3.91 per Common Unit, for the year ended September 29, 2007 compared to net income of $90.7 million, or $2.84 per Common Unit, in the prior year. EBITDA for fiscal 2007 of $197.8 million increased $32.5 million, or 19.7%, compared to EBITDA of $165.3 million in the prior year.
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 – deferred taxes of $3.8 million.
By comparison, EBITDA and net income for fiscal 2006 were unfavorably impacted by $17.5 million and $18.6 million, respectively, as a result of certain significant items relating mainly to (i) $6.1 million of restructuring charges primarily related to severance benefits associated with our field realignment and the restructuring of our HVAC business; (ii) incremental professional services fees of $5.0 million associated with the GP Exchange Transaction consummated on October 19, 2006; (iii) a non-cash pension settlement charge of $4.4 million; (iv) a charge of $2.0 million within cost of products sold to reduce the carrying value of service inventory that will no longer be marketed by our
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customer service centers; and (v) $1.1 million included within depreciation and amortization expense attributable to impairment of assets affected by the field realignment.
EBITDA represents net income before deducting interest expense, income taxes, depreciation and amortization. Our management uses EBITDA as a measure of liquidity and we are including 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:
2007
2006 Net income (loss)Fiscal Year 2006 Compared to Fiscal Year 2005
Fiscal 2006 includes 53 weeks of operations compared to 52 weeks in the prior year, which has affected operating results for all categories discussed below.
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Revenues
2006
2005
(Decrease)
Increase /
(Decrease) RevenuesTotal revenues increased $41.5 million, or 2.6%, to $1,657.1 million for the year ended September 30, 2006 compared to $1,615.6 million for the year ended September 24, 2005, driven primarily by higher average selling prices resulting from significantly higher commodity prices, offset to an extent by lower volumes in our propane and fuel oil and refined fuels segments. As reported by NOAA, average temperatures in our service territories were 11% warmer than normal for fiscal 2006 compared to 6% warmer than normal temperatures in fiscal 2005. While the fiscal 2006 heating season began with temperatures that were 5% warmer than normal in the first quarter, significantly warmer than normal temperatures, particularly during the critical heating months of January and February 2006 which were 20% warmer than normal, had a significant negative impact on volumes sold. In the commodities markets, the high propane and fuel oil prices experienced throughout fiscal 2005 continued into fiscal 2006, thus continuing to negatively impact volumes as a result of customer conservation.
Revenues from the distribution of propane and related activities of $1,081.6 million for the year ended September 30, 2006 increased $116.3 million, or 12.0%, compared to $965.3 million in the prior year, primarily due to the impact of higher average selling prices in line with significantly higher product costs, offset to an extent by the impact of lower volumes. Retail propane gallons sold in fiscal 2006 decreased 49.2 million gallons, or 9.5%, to 466.8 million gallons from 516.0 million gallons in the prior year. Propane volumes sold were negatively affected by the impact of warmer weather, customer conservation efforts, and our effort to focus on higher margin residential customers. Average propane selling prices increased 19.9% as a result of higher commodity prices for propane. The average posted price of propane during fiscal 2006 increased 21.8% compared to the average posted prices in the prior year. Additionally, included within the propane segment are revenues from wholesale and risk management activities of $74.4 million for the year ended September 30, 2006 which was comparable to the prior year.
Revenues from the distribution of fuel oil and refined fuels of $356.5 million for the year ended September 30, 2006 decreased $74.7 million, or 17.3%, from $431.2 million in the prior year. Sales of fuel oil and refined fuels amounted to 145.6 million gallons during fiscal 2006 compared to 244.5 million gallons in the prior year, a decrease of 98.9 million gallons, or 40.4%. Lower volumes in our fuel oil and refined fuels segment were attributable primarily to our continued efforts to exit certain lower margin diesel and gasoline businesses which resulted in an approximate decrease of 51.8 million gallons compared to the prior year, combined with the impact of high prices on fuel oil volumes, as well as the impact on volumes from the decision to eliminate the 2005 fiscal year fuel oil ceiling program (‘‘Ceiling Program’’). Average selling prices in our fuel oil and refined fuels segment increased 38.8% as a result of higher fuel oil commodity prices, coupled with the decreased emphasis on lower priced diesel and gasoline businesses and the shift in our pricing strategy at the field level following the elimination of the restrictions from the Ceiling Program. The average posted price of fuel oil during fiscal 2006 increased 21.4% compared to the average posted prices in the prior year.
Revenues for the year ended September 30, 2006 were favorably impacted by an 18.7% increase in our natural gas and electricity segment, which increased to $122.1 million from $102.8 million in the prior year, primarily as a result of a rise in electricity volumes coupled with increases in average selling prices for natural gas and electricity in line with higher commodity prices. Revenues in our
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HVAC segment declined 17.8%, to $87.3 million during fiscal 2006 compared to $106.1 million in the prior year, primarily as a result of the decision during the third quarter of fiscal 2006 to reorganize the HVAC segment and to reduce the level of HVAC installation activities. The focus of our ongoing service offerings will be in support of our existing propane, refined fuels and natural gas and electricity segments, thus reducing overall HVAC segment revenues.
Cost of Products Sold
2006
2005
(Decrease)
Increase /
(Decrease) Cost of products soldCost of products sold decreased $17.9 million to $1,051.8 million for the year ended September 30, 2006, compared to $1,069.7 million in the prior year. The decrease results primarily from the lower sales volumes described above, offset to an extent by higher commodity prices for propane and fuel oil. Cost of products sold for fiscal 2006 include a $14.5 million unrealized (non-cash) gain representing the net change in fair values of derivative instruments under SFAS No. 133, ‘‘Accounting for Derivative Instruments and Hedging Activities,’’ as amended by SFAS Nos. 137, 138, 149 and 155 (‘‘SFAS 133’’), compared to a $2.5 million unrealized (non-cash) loss in the prior year (see Item 7A of this Annual Report for information on our policies regarding the accounting for derivative instruments).
Cost of products sold associated with the distribution of propane and related activities of $635.4 million increased $89.7 million, or 16.4%, compared to the prior year. Higher propane prices resulted in a $106.9 million increase in cost of products sold during fiscal 2006 compared to the prior year, partially offset by decreased propane volumes which had an impact of $48.0 million. Wholesale and risk management activities resulted in a $28.0 million increase in cost of products sold compared to the prior year.
Cost of products sold associated with our fuel oil and refined fuels segment of $272.1 million decreased $113.4 million, or 29.4%, compared to the prior year. Lower sales volumes resulted in a $154.9 million decrease in cost of products sold during fiscal 2006 compared to the prior year, partially offset by higher commodity prices which had an impact of $56.5 million compared to the prior year. Cost of products sold as a percentage of revenues in our fuel oil and refined fuels segment decreased from 89.4% during fiscal 2005 to 76.3% in fiscal 2006 primarily as a result of the elimination of the Ceiling Program which had the effect of restricting fuel oil margin opportunities in fiscal 2005. The Ceiling Program primarily affected deliveries from February through April 2005 as a result of the decision not to hedge the program; however, the inability to pass on the significant rise in the commodity prices throughout fiscal 2005 significantly affected margin opportunities. The lost margin opportunity from this fuel oil Ceiling Program had an estimated negative impact of $21.5 million on fiscal 2005 operating margins in the fuel oil and refined fuels segment. By eliminating this pricing program beginning in fiscal 2006, we no longer incur the costs of hedging deliveries made under the program and we have been successful in implementing our market-based pricing strategies in our field operations, without significant customer losses.
The increase in revenues attributable to our natural gas and electricity segment had a $12.2 million impact on cost of products sold for the year ended September 30, 2006 compared to the prior year. Cost of products sold in our HVAC segment declined $10.2 million as a result of lower
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revenues, partially offset by a charge of $3.5 million to reduce the carrying value of inventory that will no longer be actively marketed by our customer service centers.
For the year ended September 30, 2006, total cost of products sold represented 63.3% of revenues compared to 66.0% in the prior year, primarily as a result of the improved pricing strategy in the fuel oil operations following the elimination of the Ceiling Program, as well as the improved customer mix from our decision to exit certain lower margin customers in both the propane and fuel oil and refined fuels segments.
Operating Expenses
2006
2005
Decrease Operating expensesOperating expenses of $373.3 million for the year ended September 30, 2006 decreased $19.0 million, or 4.9%, compared to $392.3 million in the prior year, primarily as a result of cost savings achieved through the aforementioned field realignment efforts and restructuring of our HVAC service offerings. During the fourth quarter of fiscal 2005, we initiated plans to realign our field operations and, as a second phase of our field realignment, during the third quarter of fiscal 2006 we initiated plans to restructure our HVAC service offerings by reducing our HVAC installation activities. These efforts have significantly restructured our operating footprint and reduced our cost structure through the elimination of more than 400 positions and the retirement of nearly 700 vehicles from our fleet through the creation of routing efficiencies, generating significant savings in our fixed cost structure. As a result, payroll and benefit related expenses declined $16.6 million and savings in other operating expenses amounted to $10.6 million. In addition, bad debt expense decreased $2.4 million from improved collection efforts. These cost savings were offset to an extent by a $6.2 million increase in variable compensation resulting from the improved earnings in fiscal 2006 compared to the prior year. Additionally, fiscal 2006 operating expenses include a $4.4 million non-cash pension settlement charge in order to accelerate the recognition of a portion of unrecognized actuarial losses in our defined benefit pension plan as a result of the level of lump sum benefit payments made during fiscal 2006 from the reduction in headcount.
General and Administrative Expenses
2006
2005
Increase General and administrative expensesGeneral and administrative expenses of $63.6 million for the year ended September 30, 2006 were $16.4 million, or 34.7%, higher compared to $47.2 million in fiscal 2005. The increase was primarily attributable to a $9.2 million increase in variable compensation in line with increased earnings, incremental professional services fees of $5.0 million associated with the GP Exchange Transaction consummated on October 19, 2006 and an increase of $2.2 million in other expenses associated with our field realignment efforts.
Restructuring Charges and Severance Costs and Impairment of Goodwill. For the year ended September 30, 2006, we recorded a restructuring charge of $6.1 million related primarily to severance costs incurred to effectuate our field realignment and HVAC restructuring initiatives during fiscal 2006 resulting in the elimination of more than 400 positions. During fiscal 2005, we recorded a $2.8 million restructuring charge related primarily to employee termination costs incurred as a result of actions taken during fiscal 2005.
During fiscal 2005 we recorded a non-cash charge of $0.7 million related to the impairment of goodwill associated with our HVAC segment as a result of our annual assessment of the anticipated future cash flows from that segment.
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Depreciation and Amortization
2006
2005
Decrease Depreciation and amortizationDepreciation and amortization expense for the year ended September 30, 2006 decreased $4.6 million, or 12.4%, compared to the prior year primarily as a result of lower amortization expense on intangible assets that have been fully amortized, coupled with lower deprecation from asset retirements. Fiscal 2006 depreciation and amortization expense included a $1.1 million asset impairment charge associated with our field realignment efforts, as well as the write-down of certain assets in the all other business segment, compared to a $1.2 million impairment charge included in depreciation and amortization expense in the prior year.
Interest Expense, net
2006
2005
Increase Interest expense, netNet interest expense increased $0.3 million, or 0.8%, to $40.7 million in fiscal 2006 as a result of increased borrowings under our working capital facility during the fiscal 2006 heating season compared to the prior year.
Discontinued Operations. Discontinued operations reflect the income associated with the assets sold in the Tirzah Sale of $2.4 million and $2.8 million for fiscal year 2006 and 2005, respectively. During fiscal 2005, we also recorded a gain on sale of $1.0 million to reflect the finalization of certain purchase price adjustments with the buyer of the customer service centers sold in fiscal 2004.
Net Income (Loss) and EBITDA. We reported net income of $90.7 million for the year ended September 30, 2006 compared to a net loss of $8.1 million in the prior year. EBITDA for fiscal 2006 of $165.3 million increased $58.2 million, or 54.3%, compared to Adjusted EBITDA of $107.1 million in the prior year.
EBITDA and net income for fiscal 2006 were unfavorably impacted by $17.5 million and $18.6 million, respectively, as a result of certain significant items relating mainly to (i) $6.1 million of restructuring charges primarily related to severance benefits associated with our field realignment and the restructuring of our HVAC business; (ii) incremental professional services fees of $5.0 million associated with the GP Exchange Transaction consummated on October 19, 2006; (iii) a non-cash pension settlement charge of $4.4 million; (iv) a charge of $2.0 million within cost of products sold to reduce the carrying value of inventory that will no longer be marketed by our customer service centers; and (v) $1.1 million included within depreciation and amortization expense attributable to impairment of assets affected by the field realignment.
By comparison, Adjusted EBITDA and net loss for fiscal 2005 were unfavorably impacted by $3.5 million and $40.9 million, respectively, as a result of certain significant items relating mainly to (i) a $36.2 million loss on debt extinguishment associated with our March 31, 2005 debt refinancing; (ii) a $2.8 million restructuring charge attributable primarily to severance associated with the realignment of our field operations; (iii) a $0.7 million charge attributable to impairment of goodwill associated with our HVAC segment; (iv) a $0.8 million charge included within amortization expense attributable to the impairment of other intangible assets in our HVAC segment; and (v) $0.4 million included within depreciation expense attributable to impairment of assets affected by the field realignment. In addition to the non-recurring items impacting fiscal 2005 results, the most significant negative impact on operating results was from the approximate $21.5 million impact on margin opportunities in our fuel oil business from the Ceiling Program.
EBITDA represents net income before deducting interest expense, income taxes, depreciation and amortization. Our management uses EBITDA as a measure of liquidity and we are including it
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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 the term Adjusted EBITDA to reflect the presentation of EBITDA for the year ended September 24, 2005 exclusive of the impact of the non-cash charge for loss on debt extinguishment in the amount of $36.2 million. 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 or 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 alternatives 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 Adjusted EBITDA and (ii) a reconciliation of EBITDA and Adjusted EBITDA, as so calculated, to our net cash provided by operating activities:
2006
2005 Net income (loss)Liquidity and Capital Resources
Analysis of Cash Flows
Operating Activities. Net cash provided by operating activities for the year ended September 29, 2007 amounted to $146.0 million, a decrease of $24.3 million compared to $170.3 million in the prior year. The decrease was attributable to a $41.7 million increase in working capital and a $15.0 million increase in voluntary contributions to our defined benefit pension plan compared to the prior year, partially offset by $32.4 million in increased earnings, after adjusting for non-cash items in both periods (depreciation, amortization compensation costs recognized under our
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Restricted Unit Plan, gains on disposal of assets, pension settlement charges and deferred tax provision). The fiscal 2007 voluntary pension plan contribution of $25.0 million was made to fully fund our estimated accumulated benefit obligation, thus substantially reducing, if not eliminating, our future funding requirements. As of September 29, 2007, the funded status of our defined benefit pension plan was $5.5 million, or 103% funded.
In fiscal 2006, net cash provided by operating activities increased $131.3 million to $170.3 million, compared to $39.0 million in fiscal 2005. The increase was attributable to an $81.0 million decreased investment in working capital in comparison to the prior year, particularly in decreased accounts receivable balances as a result of steps taken during fiscal 2006 to improve collection efforts, coupled with $64.1 million higher income, after adjusting for non-cash items in both periods (depreciation, amortization, pension settlement charge, loss on debt extinguishment, impairment of goodwill and gains on disposal of assets and customer service centers); offset to an extent by a decrease in other long-term assets and liabilities of $13.8 million.
Investing Activities. Net cash used in investing activities of $19.7 million for the year ended September 29, 2007 consisted of capital expenditures of $26.8 million (including $10.0 million for maintenance expenditures and $16.8 million to support the growth of operations), offset by net proceeds of $5.8 million from the sale of property, plant and equipment and proceeds from the sale of certain customer service centers of $1.3 million. Capital spending in fiscal 2007 increased $3.7 million, or 16.0%, compared to fiscal 2006 primarily as a result of spending on information technology to finalize the integration of systems from the Agway Acquisition, as well as the timing of capital spending for our field realignment efforts, particularly to integrate certain customer service center locations.
Net cash used in investing activities of $19.1 million for the year ended September 30, 2006 consisted of capital expenditures of $23.1 million (including $11.2 million for maintenance expenditures and $11.9 million to support the growth of operations), offset by net proceeds of $4.0 million from the sale of property, plant and equipment. Capital spending in fiscal 2006 decreased $6.2 million, or 21.2%, compared to fiscal 2005 primarily as a result of (i) efforts to consolidate existing storage assets for better utilization in conjunction with our fiscal 2006 field realignment efforts thereby reducing fiscal 2006 spending needs; and (ii) a reduction from fiscal 2005 spending on information technology for the integration of Agway Energy.
Financing Activities. Net cash used in financing activities for the year ended September 29, 2007 of $90.3 million reflects quarterly distributions to Common Unitholders at a rate of $0.6625 per Common Unit in respect of the fourth quarter of fiscal 2006, at a rate of $0.6875 per Common Unit in respect of the first quarter of fiscal 2007, at a rate of $0.70 per Common Unit in respect of the second quarter of fiscal 2007 and at a rate of $0.7125 per Common Unit in respect of the third quarter of fiscal 2007. There were no borrowings under our working capital facility during fiscal 2007, nor have there been any borrowings since April 2006.
Net cash used in financing activities for the year ended September 30, 2006 of $105.1 million reflects the repayment of short-term borrowings of $26.8 million under our Revolving Credit Agreement and quarterly distributions to Common Unitholders and the General Partner at a rate of $0.6125 per Common Unit in respect of the fourth quarter of fiscal 2005 and the first and second quarters of fiscal 2006 and at a rate of $0.6375 per Common Unit in respect of the third quarter of fiscal 2006 totaling $77.8 million. This distribution amount includes a $0.3 million payment made to the General Partner reflecting a true-up of previous underpayments resulting from an error in the computation of quarterly cash distributions to the General Partner. During fiscal 2006, borrowings under the working capital facility reached $84.0 million during the peak heating season, which was fully repaid by the end of April 2006.
Summary of Long-Term Debt Obligations and Revolving Credit Lines
Our long-term borrowings and revolving credit lines consist of $425.0 million in 6.875% senior notes due December 2013 (the ‘‘2003 Senior Notes’’) and a Revolving Credit Agreement at the Operating Partnership level which provides a five-year $125.0 million term loan due March 31, 2010
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(the ‘‘Term Loan’’) and a separate working capital facility which provides available credit up to $175.0 million. There were no outstanding borrowings under the working capital facility as of September 29, 2007. There have been no borrowings under our working capital facility since April 2006. We have standby letters of credit issued under the working capital facility of the Revolving Credit Agreement in the aggregate amount of $51.0 million in support of retention levels under our self-insurance programs and certain lease obligations. Therefore, as of September 29, 2007 we had available borrowing capacity of $124.0 million under the working capital facility of the Revolving Credit Agreement. Additionally, under the third amendment to the Revolving Credit Agreement our Operating Partnership is authorized to incur additional indebtedness of up to $10.0 million in connection with capital leases and up to $20.0 million in short-term borrowings during the period from December 1 to April 1 in each fiscal year in order to meet working capital needs during periods of peak demand, if necessary. Because of our operating results and cash flow, we did not make any such short-term borrowings during fiscal 2007.
The 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 Agreement, including the Term Loan, bear interest at a rate based upon either LIBOR or Wachovia National Bank’s prime rate plus, in each case, the applicable margin. An annual facility fee ranging from 0.375% to 0.50%, based upon certain financial tests, is payable quarterly whether or not borrowings occur.
In connection with the Term Loan, our Operating Partnership also entered into an interest rate swap contract with a notional amount of $125.0 million with the issuing lender. Effective March 31, 2005 through March 31, 2010, our Operating Partnership will pay a fixed interest rate of 4.66% to the issuing lender on the notional principal amount of $125.0 million, 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. The applicable margin above LIBOR, as defined in the Revolving Credit Agreement, will be paid in addition to this fixed interest rate of 4.66%.
Under the Revolving Credit Agreement, our Operating Partnership must maintain a leverage ratio (the ratio of total debt to EBITDA) of less than 4.0 to 1 and an interest coverage ratio (the ratio of EBITDA to interest expense) of greater than 2.5 to 1 at the Partnership level. The Revolving Credit Agreement and the 2003 Senior Notes both contain various restrictive and affirmative covenants applicable to our Operating Partnership and us, respectively. These covenants include (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. We were in compliance with all covenants and terms of all of our debt agreements as of September 29, 2007.
Partnership Distributions
We are required to make distributions in an amount equal to all of our Available Cash, as defined in the Third Amended and Restated 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. As a result of the GP Exchange Transaction, all IDRs formerly held by the General Partner have been cancelled and the General Partner is not entitled to receive any cash distributions in respect of its general partner interests. Accordingly, beginning with
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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 the holders of Common Units, including the 2.3 million Common Units issued in the GP Exchange Transaction.
On October 25, 2007, we announced a quarterly distribution of $0.75 per Common Unit, or $3.00 on an annualized basis, in respect of the fourth quarter of fiscal 2007 payable on November 13, 2007 to holders of record on November 6, 2007. This quarterly distribution included an increase of $0.0375 per Common Unit, or $0.15 per Common Unit on an annualized basis, from the previous quarterly distribution rate representing the fifteenth increase since our recapitalization in 1999 and a 13% 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 2007, 2006 or 2005. During 2007, we made a voluntary cash contribution from cash on hand of $25.0 million to our defined benefit pension plan in order to fully fund our estimated accumulated benefit obligation, thus substantially reducing, if not eliminating, our future funding requirements. As a result of our voluntary contributions and improved asset returns in our pension asset portfolio during the last several years, the fair value of plan assets exceeded the accumulated benefit obligation of the defined benefit pension plan by $5.5 million as of September 29, 2007. This overfunded position resulted in the elimination of the additional minimum liability of $63.5 million with a corresponding increase to accumulated other comprehensive loss, a component of partners’ capital.
At the end of fiscal 2007, we adopted SFAS No. 158, ‘‘Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – An Amendment of FASB Statements No. 87, 88, 103 and 132R’’ (‘‘SFAS 158’’), which requires companies to recognize the funded status of pension and other postretirement benefit plans as an asset or liability on sponsoring employers’ balance sheets and to recognize changes in the funded status in comprehensive income (loss) in the year the changes occur. This adoption resulted in a $48.0 million reduction to the prepaid pension asset and a $5.0 million decrease to accrued postretirement liability, with the net amount of $43.0 million recorded as a reduction in the net assets of the Partnership to accumulated other comprehensive loss. As of September 29, 2007, the fair value of plan assets exceeded the projected benefit obligation of the defined benefit pension plan by $5.5 million, which was recognized on the balance sheet as an asset in accordance with SFAS 158.
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, pursuant to SFAS No. 88 ‘‘Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,’’ 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 in accordance with SFAS No. 87 ‘‘Employers’ Accounting for Pensions.’’ A similar non-cash pension settlement charge of $4.4 million was recorded in fiscal 2006 as a result of the level of lump sum benefit payments. Additional pension settlement charges may be required in future periods depending on the level of lump sum benefit payments.
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 fully fund the accumulated benefit obligation, as described above, 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
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resulted in the $25.0 million voluntary contribution described above, and a change in the asset allocation to reflect a greater concentration of fixed income securities.
There can be no assurance that future declines in capital markets, or interest rates, will not have an adverse impact on our results of operations or cash flow. However, with the overfunded status of the plan, coupled with the shift in investment strategy to a higher concentration of fixed income securities, we expect over the long-term that the returns on plan assets should match increases in the accumulated benefit obligation resulting from interest credits, this maintaining a fully funded status. For purposes of computing the actuarial valuation of projected benefit obligations, we increased the discount rate assumption from 5.50% as of September 30, 2006 to 6.00% as of September 29, 2007 to reflect current market expectations related to long-term interest rates and the projected duration of our pension obligations based on a benchmark index with similar characteristics as the expected cash flow requirements of our defined benefit pension plan over the long-term. Additionally, for purposes of the computation of the net periodic pension cost for fiscal 2007, 2006 and 2005 we assumed increased long-term rates of return on plan assets of 8.00%, 8.00% and 7.50%, respectively, based on the investment mix of our pension asset portfolio, historical asset performance and expectations for future performance. For purposes of the computation of the net periodic pension cost for fiscal 2008, we expect the rate of return on plan assets will be reduced to reflect the higher concentration of fixed income securities. Based on information provided by our actuaries, we do not project any future funding requirements.
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 such benefits if they reached a specific retirement age while working for the Partnership. Effective January 1, 2000, we terminated our postretirement benefit plan for all eligible employees retiring after March 1, 1998. All active and eligible employees who were to receive 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.
Long-Term Debt Obligations and Operating Lease Obligations
Contractual Obligations
Long-term debt obligations and future minimum rental commitments under noncancelable operating lease agreements as of September 29, 2007 are due as follows:
2008
2009
2010
2011
and
thereafterAdditionally, we have standby letters of credit in the aggregate amount of $51.0 million, in support of retention levels under our casualty insurance programs and certain lease obligations, which expire periodically through October 25, 2008.
Operating Leases
We lease certain property, plant and equipment for various periods under noncancelable operating leases, including approximately 53% of our vehicle fleet, approximately 25% of our customer service centers and portions of our information systems equipment. Rental expense under operating leases was $19.6 million, $27.2 million and $28.6 million for fiscal 2007, 2006 and 2005, respectively. Future minimum rental commitments under noncancelable operating lease agreements as of September 29, 2007 are presented in the table above.
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Off-Balance Sheet Arrangements
Guarantees
We have residual value guarantees associated with certain of our operating leases, related primarily to transportation equipment, with remaining lease periods scheduled to expire periodically through fiscal 2014. Upon completion of the lease period, we guarantee that the fair value of the equipment will equal or exceed the guaranteed amount, or we 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 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 $15.3 million. The fair value of residual value guarantees for outstanding operating leases was $-0- as of September 29, 2007 and September 30, 2006.
Recently Issued Accounting Standards
In February 2007, the Financial Accounting Standards Board (‘‘FASB’’) issued SFAS No. 159, ‘‘The Fair Value Option for Financial Assets and Financial Liabilities’’ (‘‘SFAS 159’’). Under SFAS 159, entities may elect to measure specified financial instruments and warranty and insurance contracts at fair value on a contract-by-contract basis, with changes in fair value recognized in earnings each reporting period. SFAS 159 is effective for fiscal years beginning after November 15, 2007, which will be our 2009 fiscal year beginning September 28, 2008. We are currently in the process of evaluating the impact that SFAS 159 may have on our consolidated financial position, results of operations and cash flows.
In September 2006, the FASB issued SFAS No. 157, ‘‘Fair Value Measurements’’ (‘‘SFAS 157’’). SFAS 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. It also establishes a fair value hierarchy that prioritizes information used in developing assumptions when pricing an asset or liability. Like SFAS 159 above, SFAS 157 will be effective for fiscal years beginning after November 15, 2007, which will be our 2009 fiscal year beginning September 28, 2008. We are currently in the process of evaluating the impact that SFAS 157 may have on our consolidated financial position, results of operations and cash flows.
In June 2006, the FASB issued FASB Interpretation No. 48, ‘‘Accounting for Uncertainty in Income Taxes – An Interpretation of FASB Statement No. 109’’ (‘‘FIN 48’’). FIN 48 requires companies to determine whether it is more likely than not that a tax position will be sustained upon examination by the appropriate taxing authorities before any part of the benefit can be recorded in the financial statements. FIN 48 is effective for fiscal years beginning after December 15, 2006, which will be our 2008 fiscal year beginning September 30, 2007. We are currently in the process of assessing the impact that FIN 48 will have on our consolidated financial statements and currently do not expect that adoption of FIN 48 will have a material impact on our financial position, results of operation or cash flows.
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Table of ContentsCommodity 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 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. In certain instances, and when market conditions are favorable as was the case in the fuel oil market during the first half of fiscal 2007, 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 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 given the time of year. Typically, our on hand priced position does not exceed more than four weeks of our supply needs and, during the peak heating season, typically not more than two weeks of supply is maintained in inventory. 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 SFAS 133, qualify for and are designated as a normal purchase or normal sale contract. Such contracts are exempted from the fair value accounting requirements of SFAS 133 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 options (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. 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. 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.
As a result of various market factors during the first half of fiscal 2007, particularly commodity price volatility during the first four months of the fiscal year, we experienced additional margin opportunities due to favorable pricing under certain supply arrangements and from our hedging and risk management activities. We attribute approximately $14.7 million of the fiscal 2007 profitability to the favorable supply and market factors. However, supply and risk management transactions may not always result in increased product margins and there can be no assurance that these favorable market conditions will be present in the future in order to provide the additional margin opportunities realized during fiscal 2007.
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Table of ContentsMarket 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 on 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 the trading of 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.
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 forward and 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 credit risk of non-performance.
Interest Rate Risk
A portion of our long-term borrowings bear interest at a variable rate based upon either LIBOR or Wachovia National Bank’s prime rate, plus an applicable margin depending on the level of our total leverage. 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. On March 31, 2005, we entered into a $125.0 million interest rate swap contract in conjunction with the Term Loan facility under the Revolving Credit Agreement. The interest rate swap is being accounted for under SFAS 133 and has been designated as a cash flow hedge. Changes in the fair value of the interest rate swap are recognized in other comprehensive (loss) income (‘‘OCI’’) until the hedged item is recognized in earnings. At September 29, 2007, the fair value of the interest rate swap was ($0.3) million representing an unrealized loss and was included within other liabilities.
Derivative Instruments and Hedging Activities
All of our derivative instruments are reported on the balance sheet, within other current assets or other current liabilities, at their fair values pursuant to SFAS 133. 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 used to hedge future purchases 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 under SFAS 133, are recorded within cost of products sold as they occur.
At September 29, 2007, the fair value of derivative instruments described above resulted in derivative assets (unrealized gains) of $2.5 million included within prepaid expenses and other current assets and derivative liabilities (unrealized losses) of $0.5 million included within other current liabilities. Cost of products sold included unrealized (non-cash) losses in the amount of $7.6 million for the year ended September 29, 2007 compared to unrealized (non-cash) gains of $14.5 million for the year ended September 30, 2006, attributable to the change in fair value of derivative instruments not designated as cash flow hedges. As of September 29, 2007, unrealized gains on derivative instruments designated as cash flow hedges in the amount of $1.4 million were included in OCI and are expected to be recognized in earnings during the next 12 months as the hedged transactions occur.
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Table of ContentsSensitivity Analysis
In an effort to estimate our exposure to unfavorable market price changes in propane or fuel oil related to our open positions under derivative instruments, we developed a model that incorporates the following data and assumptions:
Based on the sensitivity analysis described above, the hypothetical 10% adverse change in market prices for each of the future months for which a future, forward and/or option contract exists indicates either future losses or a reduction in potential future gains of $5.8 million as of September 29, 2007. 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. The average posted price of propane on September 29, 2007 at Mont Belvieu, Texas (a major storage point) was $1.341 per gallon as compared to $0.9475 per gallon on September 30, 2006. The average posted price of fuel oil on September 29, 2007 at Linden, New Jersey was $2.2379 per gallon as compared to $1.685 per gallon on September 30, 2006. The average posted price of propane on November 20, 2007 at Mont Belvieu, Texas was $1.563 per gallon, representing a 16.6% increase since the end of fiscal 2007. The average posted price of fuel oil on November 20, 2007 at Linden, New Jersey was $2.6739 per gallon, representing a 19.5% increase since the end of fiscal 2007.
As of September 29, 2007, our open positions under derivative instruments reflected a net short position (sell contracts) aggregating $32.2 million.
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Table of ContentsOur 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
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).
Quarter
Quarter
Quarter
Quarter
(a)(g)
(a) Fiscal 200748
Table of Contents (b) These amounts include gains from the disposal of property, plant and equipment of $2.8 million for fiscal 2007 and $1.0 million for fiscal 2006. (c) Gain on disposal of discontinued operations reflects (i) a $1.0 million gain on the non-cash exchange of nine non-strategic customer service centers for three customer service centers of another company in Alaska during the first quarter of fiscal 2007; (ii) a $0.2 million gain on the sale of one customer service center for net cash proceeds of $0.3 million during the third quarter of fiscal 2007; and (iii) a $0.7 million gain on the sale of two customer service centers for net cash proceeds of $1.0 million during the fourth quarter of fiscal 2007. These gains were accounted for within discontinued operations pursuant to SFAS 144. (d) On October 2, 2007, we completed the Tirzah Sale. As a result of this sale, a gain of approximately $40.0 million will be reported as a gain from the disposal of discontinued operations in our results for the first quarter of fiscal 2008. The results of operations from the Tirzah facilities have been reported within discontinued operations. Because the transaction closed subsequent to the end of fiscal 2007, our cash on hand at September 29, 2007 does not include the net proceeds of approximately $54.0 million. (e) Computations of earnings per Common Unit for the year ended September 29, 2007 were performed in accordance with SFAS No. 128 ‘‘Earnings per Share’’ (‘‘SFAS 128’’) by dividing net income by the weighted average number of outstanding Common Units. For fiscal 2006, earnings per Common Unit were performed in accordance with Emerging Issues Task Force consensus 03-6 ‘‘Participating Securities and the Two-Class Method Under FAS 128’’ (‘‘EITF 03-6’’), when applicable. EITF 03-6 requires, among other things, the use of the two-class method of computing earnings per unit when participating securities exist. 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 of computing income per Common Unit under EITF 03-6 is no longer applicable.The requirements of EITF 03-6 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 the third and fourth quarters of fiscal 2006. Net income and income from continuing operations per Common Unit presented in this table for the first and second quarters of fiscal 2006 and for the year ended September 30, 2006 reflect the impact of the application of EITF 03-6. Basic net income (loss) per Common Unit computed under SFAS 128 is computed by dividing net income (loss), after deducting our General Partner’s interest, by the weighted average number of outstanding Common Units. 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 2000 Restricted Unit Plan. For purposes of the computation of income per Common Unit for the year ended September 30, 2007, earnings that would have been allocated to the General Partner for the period prior to the GP Exchange Transaction were not significant.
(f) EBITDA represents net income before deducting interest expense, income taxes, depreciation and amortization. Our management uses EBITDA as a measure of liquidity and we are including 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 and quarter-to-quarter basis. Moreover, our revolving credit agreement requires us to use EBITDA as a component in calculating our leverage and interest49
Table of Contents 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 (amounts in thousands):
Quarter
Quarter
Quarter
Quarter
Year Net income (loss)50
Table of Contents
(g) The fourth quarter of fiscal 2007 includes a $3.8 million adjustment related to the provision for income taxes – deferred taxes related to the utilization of net operating losses in the first quarter of fiscal 2007.
Quarter
Quarter
Quarter
Quarter
Year Net income (loss)51
Table of ContentsNone.
DISCLOSURE CONTROLS AND PROCEDURES. The Partnership maintains disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (the ‘‘Exchange Act’’)) that are designed to provide reasonable assurance that information required to be disclosed in the Partnership’s filings under the Exchange Act is recorded, processed, summarized and reported within the periods specified in the rules and forms of the SEC and that such information is accumulated and communicated to the Partnership’s management, including its principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.
Before filing this Annual Report, the Partnership completed an evaluation under the supervision and with the participation of the Partnership’s management, including the Partnership’s principal executive officer and principal financial officer, of the effectiveness of the design and operation of the Partnership’s disclosure controls and procedures as of September 29, 2007. Based on this evaluation, the Partnership’s principal executive officer and principal financial officer concluded that the Partnership’s disclosure controls and procedures were effective at the reasonable assurance level as of September 29, 2007.
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 29, 2007, 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 INTERNAL CONTROL OVER FINANCIAL REPORTING. Management of the Partnership is responsible for establishing and maintaining adequate internal control over financial reporting. The Partnership’s internal control over financial reporting is designed to provide reasonable assurance as to the reliability of the Partnership’s financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
The Partnership’s management has assessed the effectiveness of the Partnership’s internal control over financial reporting as of September 29, 2007. In making this assessment, the Partnership used the criteria established by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in ‘‘Internal Control-Integrated Framework.’’ These criteria are in the areas of control environment, risk assessment, control activities, information and communication, and monitoring. The Partnership’s assessment included documenting, evaluating and testing the design and operating effectiveness of its internal control over financial reporting.
Based on the Partnership’s assessment, as described above, management has concluded that, as of September 29, 2007, the Partnership’s internal control over financial reporting was effective.
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Table of ContentsManagement’s assessment of the effectiveness of the Partnership’s internal control over financial reporting as of September 29, 2007 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears in the ‘‘Report of Independent Registered Public Accounting Firm’’ on page F-2 of this Annual Report.
None.
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Table of ContentsPART III
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 seven Supervisors, who serve on the Board of Supervisors pursuant to the terms of the Partnership Agreement. Prior to adoption of the current Partnership Agreement on October 19, 2006, following approval thereof by the Common Unitholders, Common Unitholders elected three Supervisors to serve a three-year term and the General Partner appointed two Supervisors. Under the current Partnership Agreement, all Supervisors are elected by the Common Unitholders for three-year terms and the two Supervisors appointed by the General Partner, Messrs. Alexander and Dunn, will continue to serve until the next Tri-Annual Meeting of the Unitholders (currently scheduled for fiscal 2009), at which meeting all Supervisors will be elected by the Common Unitholders.
On January 31, 2007, acting on authority granted to it under the Partnership Agreement, the Board of Supervisors increased its size from five to seven Supervisors and appointed John D. Collins and Jane Swift to fill the vacancies thereby created, effective April 25, 2007. Mr. Collins and Ms. Swift will continue to serve on the Board of Supervisors until the next Tri-Annual Meeting of the Unitholders, at which time they will be subject to re-election by the Common Unitholders.
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 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 controls 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; and (d) performance of the internal audit function and the independent registered public accounting firm.
Mr. Collins has advised the Board of Supervisors that he currently serves on the audit committees of four public companies, including the Partnership. In accordance with the rules of the NYSE, the Board of Supervisors has determined that Mr. Collins’ simultaneous service on four audit committees would not impair his ability to effectively serve on the Audit Committee of the Partnership’s Board of Supervisors.
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 Item 407 of Regulation S-K as of the date of this Annual Report. Mr. Logan, Chairman of the Audit Committee, 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. On October 31, 2007, the Audit Committee approved the nomination to appoint Mr. Collins as Chairman of the Audit Committee, effective January 24, 2008. Investors and other parties interested in communicating directly with the non-management supervisors
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Table of Contentsas a group may do so by writing to the Non-Management Members of the Board of Supervisors, c/o Company Secretary, Suburban Propane Partners, L.P., P.O. Box 206, Whippany, New Jersey 07981-0206.
Board of Supervisors and Executive Officers of the Partnership
The following table sets forth certain information with respect to the members of the Board of Supervisors and our executive officers as of November 20, 2007. Officers are appointed by the Board of Supervisors for one-year terms and Supervisors are elected by the Unitholders for three-year terms.
Mr. Alexander has served as Chief Executive Officer and as a Supervisor since March 1996, and as President from October 1996 until May 2005. He was Executive Vice Chairman from March 1996 through October 1996. From 1989 until joining the Partnership, Mr. Alexander was an officer of Hanson Industries (the United States management division of Hanson plc, a global diversified industrial conglomerate), most recently Senior Vice President – Corporate Development. Mr. Alexander is the sole member of the General Partner. Mr. Alexander is a Director of Kaydon Corporation.
Mr. Dunn became President in May 2005. From June 1998 until that date 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. Stivala has served as 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. D’Ambrosio became Treasurer in November 2002 and was additionally made a Vice President in October 2007. He served as Assistant Treasurer from October 2000 to November 2002
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Table of Contentsand 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. Anderson has served as Northeast Area Vice President since March 2007. He joined the Partnership in December 2003 as a Region General Manager upon the Partnership’s acquisition of Agway Energy, where he had also served as Region General Manager since before 2002.
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 Southeast and Western Area Vice President since March 2007. Prior to that he was 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 became Vice President – Supply in 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 supply area, most recently as Managing Director.
Mr. Keating has served as Vice President – Human Resources and Administration since July 1996. He previously held senior human resource positions at Hanson Industries and Quantum Chemical Corporation (‘‘Quantum’’), a predecessor of the Partnership.
Mr. Wienberg has served as Vice President – Operational Planning and Analysis 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 became Controller in 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. From 2003 to September 2006, Mr. Logan was a Director and Chairman of the Finance Committee of the Board of Directors of TransMontaigne Inc., which provided logistical services (i.e. pipeline, terminaling and marketing) to producers and end-users of refined petroleum products. From 1995 to 2002, Mr. Logan was Executive Vice President/Finance, Treasurer and a Director of TransMontaigne Inc. From 1987 to 1995, Mr. Logan served as Senior Vice President of Finance and a Director of Associated Natural Gas Corporation, an independent gatherer and marketer of natural gas, natural gas liquids and crude oil. Mr. Logan is also a Director of Graphic Packaging, Inc. and Hart Energy Publishing LLP.
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. Mr. Stookey is a 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).
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Table of ContentsMr. 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 Famous Brands, LLC and Excelsior 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 – 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 Animated Speech Company, Sally Ride Science Inc. and WellCare Health Plans, 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 2007.
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. Copies of our Code of Ethics and our Code of Business Conduct are available without charge from our website at www.suburbanpropane.com or upon written request directed to: Suburban Propane Partners, L.P., Investor Relations, P.O. Box 206, Whippany, New Jersey 07981-0206. Any amendments to, or waivers from, provisions of our Code of Ethics or our Code of Business Conduct that apply to our principal executive officer, principal financial officer and principal accounting officer will be posted on our website.
Corporate Governance Guidelines
We have adopted Corporate Governance Guidelines and Policies in accordance with the NYSE corporate governance listing standards in effect as of the date of this Annual Report. Copies of our Corporate Governance Guidelines are 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. Copies of our Audit Committee Charter are 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
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Table of Contentswith the NYSE corporate governance listing standards in effect as of the date of this Annual Report. Copies of our Compensation Committee Charter are 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. Mr. Alexander submitted his Annual CEO Certification for 2007 to the NYSE without qualification.
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Table of ContentsCOMPENSATION DISCUSSION AND ANALYSIS
This Compensation Discussion and Analysis provides a review of 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, President, the Chief Financial Officer, the other two most highly compensated executive officers and one individual, Mr. Jolly, for whom disclosure would have been required but for the fact that he no longer served as an executive officer at the conclusion of fiscal 2007.
Executive Compensation Philosophy and Components
The objectives of our executive compensation program are as follows:
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 achieving this goal.
The principal components of the compensation we provide to our named executive officers are as follows:
We align the short-term and long-term interests of our executive officers with the short-term and long-term interests of our Unitholders by:
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 all managing directors, vice presidents and the named executive officers.
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Table of ContentsAnnually, the Vice President of Human Resources 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 fiscal 2007 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 was derived from the Mercer Human Resource Consulting, Inc. (‘‘Mercer’’) Benchmark Database containing information obtained from surveys of over 2,500 organizations and 167 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 annual revenues of between $1.0 billion and $2.5 billion per year. 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, due to an overall increase in salaries in the New York area, the Committee may consider using the mean of the reported data as a benchmark in the future.
In establishing the executive compensation packages for fiscal 2007, the members of the Committee also focused on lessening the shortfalls between the compensation packages that we provide to our executive officers and the median compensation paid by the companies whose data underlie the Mercer benchmark database. The Committee does not, however, set specific percentile targets for total compensation of our executive officers compared to the total compensation of the peer group.
In making its decisions regarding our fiscal 2007 executive compensation packages, the Committee first reviewed the total cash compensation opportunities that we provided to our executive officers during fiscal 2006. Each executive officer’s ‘‘total cash compensation opportunities’’ consist of base salary, an annual cash bonus, and long-term incentives. The Committee then compared each executive officer’s total cash compensation opportunity to the total median 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 2007 compensation packages for our executive officers that emphasize the performance-based components of compensation.
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 Vice President of Human Resources, our CEO presented the Committee with information comparing each executive officer’s compensation to the median compensation figures provided in the Mercer Database. Additionally, based on our budgeted fiscal 2007 financial performance, our CEO presented the Committee with budgeted EBITDA for purposes of setting the targets for our annual cash bonus plan.
Among other duties, the Committee has overall responsibility for:
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Table of ContentsAllocation 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 their position. The base salary for each executive officer is the only fixed component of compensation. All other compensation, including annual cash bonuses and long-term incentive compensation, is variable in nature as it is dependent upon achievement of certain performance measures. The following table summarizes the components as percentages of each named executive officer’s total cash compensation opportunity.
Target
Incentive Mark A. Alexander(1)In allocating compensation among these elements, 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 approximately 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, individual performance and years in one’s 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
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Table of Contentsthe existing level of equity ownership of each of our named executive officers when granting awards under our 2000 Restricted Unit Plan and the 2003 Long-Term Incentive Plan (see below for a description of both plans). The compensation packages for our Chief Executive Officer and our President are 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 2007 base salary increases, the Committee compared each executive officer’s fiscal 2006 base salary with the corollary median salary provided in the Mercer study. 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 2007, each named executive officer received adjustments to his base salary in accordance with the philosophy and process described above, ranging from 0% to 28%. A subsequent 8% adjustment was made to Mr. Boyd’s base salary upon his promotion to vice president during fiscal 2007. In the event of a promotion such as Mr. Boyd’s or a new hire, the Committee reviews and takes action at its next meeting.
The fiscal 2007 adjustments to each named executive officer’s base salary were as follows:
The total base salary paid to each named executive officer in fiscal 2007 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
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Table of Contentsbonus 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. Although this 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 2007, our Chief Executive Officer did not make any such recommendations to the Committee.
The terms of our annual bonus plan provide for cash payments of a specified percentage (which, in fiscal 2007, ranged from 60% to 100%) of our named executive officers’ annual base salaries (‘‘target cash bonus’’) if, for the fiscal year, actual EBITDA 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 from the application of SFAS 133 reported within cost of products sold in our statement of 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 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.
For fiscal 2007, our budgeted cash bonus plan EBITDA was $171.7 million. Our actual cash bonus plan EBITDA was such that each of our executive officers earned 110% of his target cash bonus. The following table provides the fiscal 2007 budgeted cash bonus plan EBITDA targets that were established at the October 17, 2006 Compensation Committee meeting:
would have been Earned if
Actual Cash Bonus Plan
EBITDA Equaled the Figure
in the Previous Column $188.9The bonuses earned under the annual cash bonus plan by each of our named executive officers are reported in the column titled ‘‘Non-Equity Incentive Plan Compensation ($)’’ in the Summary Compensation Table below.
The 2007 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 2007 are summarized as follows:
Cash Bonus as
a % of Salary
Cash Bonus
Actual Cash
Bonus Earned Mark A. Alexander(1)63
Table of ContentsFor purposes of establishing the cash bonus targets for fiscal 2008, at its meeting on October 31, 2007 the Committee reviewed and approved our fiscal 2008 budget. The budget is developed annually using a bottom-up process factoring in reasonable growth targets 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 will 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%, 109% and 0% of their respective target cash bonus for fiscal 2007, 2006 and 2005, 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, primarily consisting 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, Ferrellgas and Inergy (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:
At the beginning of the three-year measurement period, each executive officer’s unvested grant 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 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:
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Table of ContentsThe three-year measurement period of the fiscal 2005 award ended simultaneously with the conclusion of fiscal 2007. The TRU for the fiscal 2005 award fell within the second highest quartile. The following is a summary of the cash payouts related to the fiscal 2005 award earned by our named executive officers at the conclusion of fiscal 2007.
The following is a summary of the quantity of phantom units that signify the unvested grants to our named executive officers during fiscal years 2006 and 2007 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 our fiscal year 2008 for the fiscal 2006 award and at the end of our fiscal year 2009 for the fiscal 2007 award).
2006 Award
2007 Award Mark A. AlexanderThe peer group members selected by the Committee for the fiscal 2005 award comprised both energy and pipeline-related publicly-traded partnerships as well as two energy-related corporations because the Committee believed it reasonable to measure our performance against the performance of a peer group consisting of diverse energy providers. The following table lists, in alphabetical order, the names and ticker symbols of the peer group used to measure our performance during the fiscal 2005 LTIP-2 award’s three-year measurement period:
2005 LTIP-2 Award Peer Group
(Three-year Measurement Period Completed)
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Table of ContentsThe peer group members selected by the Committee for the fiscal 2006 and fiscal 2007 awards were somewhat different because the Committee decided that the peer group should consist entirely of publicly-traded partnerships, inclusive of all propane-related partnerships. The Committee decided this 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 2006 and fiscal 2007 LTIP-2 awards’ three-year measurement periods:
2006 and 2007 LTIP-2 Awards Peer Group
(Completed Two Years and Three Years of Each Award’s
Three-year Measurement Period, Respectively)
The LTIP-2 document also contains a retirement provision that provides for the immediate termination of the three-year measurement period for all outstanding LTIP-2 awards held by a participant upon retirement. TRU is 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 has been earned by the retiree.
Because LTIP-2 is a phantom unit plan, compensation expense generated by this plan is charged to earnings in accordance with SFAS 123R. As a result, 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.
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 2007, there remained 71,792 restricted units available for future grants.
When the Committee authorizes a grant of restricted units, the unvested units underlying a grant do not provide the grantee with voting rights and do not pay or accrue distributions during the vesting period. Restricted unit grants vest as follows: 25% on the third and fourth anniversaries of the grant date and the remaining 50% on the fifth anniversary of the grant date. Unvested grants 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.
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Table of ContentsThe RUP document contains a retirement provision that provides for the immediate vesting of all unvested RUP grants held by a retiring participant who meets all three of the following conditions on his or her retirement date:
On October 31, 2007, in order to comply with the regulations promulgated under Internal Revenue Code (‘‘IRC’’) Section 409(A), 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 the Partnership issues outstanding Common Units to such Participants.
All RUP grants are made at the discretion of the Committee. Although the reasons for awarding a grant can vary, the objective of awarding a grant 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 awards RUP grants include, but are not limited to, the following:
In determining the quantity of restricted units to award to each executive officer and other key employees, the Committee considers, without limitation:
In addition, in establishing the level of restricted units to grant to our executive officers, the Committee considers the 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 General Partner.
Our practice is to determine the dollar amount of equity compensation that we want to provide. 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. The grant date for RUP grants coincides with the date of grant by the Committee typically at its October or November meeting. However, in the few cases that grants were approved at other Committee meetings during the year, the effective date of the grant invariably coincided with the date of the meeting.
On October 31, 2007, the Committee adopted a policy with respect to the effective date of subsequent grants 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
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Table of ContentsRUP in a given calendar year will be the first business day in the month of December of that calendar year. If, at the discretion of the Committee, an award is expressed as a dollar amount, then such award will be converted into the number of restricted units, as of the effective date of grant, obtained by dividing the dollar amount of the award by the average of the closing prices, on the New York Stock Exchange, of one Common Unit of the Partnership for the 20 trading days immediately prior to that effective date of grant.
During fiscal 2007, RUP grants were awarded to the following named executive officers:
Restricted Units Robert M. PlanteMr. Plante’s and Mr. Keating’s RUP grants were awarded to them by the Committee in recognition of their exemplary performance over the past ten years. Mr. Boyd’s RUP grant was awarded in recognition of his performance and promotion to vice president.
Compensation expense for unvested RUP grants is recognized ratably over the vesting periods and is net of estimated forfeitures in accordance with SFAS 123R. The RUP-related SFAS 123R expense recognized in the Partnership’s fiscal 2007 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.
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 bonus plan, LTIP-2 and the RUP to expressly make future awards under such plans subject to the Incentive Compensation Recoupment Policy.
Long-Term Incentive Plan of October 1, 1997
Effective October 1, 1997, we adopted a non-qualified, unfunded long-term incentive plan for executive officers and other key employees (‘‘LTIP-1’’). Effective September 30, 2004, we discontinued LTIP-1 with the effect that no new awards will be made after that date; however, all awards for which the performance criteria had been satisfied prior thereto will continue to vest and be payable in accordance with their terms. LTIP-1 awards were based on a percentage of base salary and were subject to the achievement of certain performance criteria, including our ability to earn sufficient funds to make cash distributions on our Common Units with respect to the fiscal years for which the awards were granted. Because all performance criteria for LTIP-1 were satisfied during the fiscal years for which any outstanding awards were granted, the Summary Compensation Table below contains only interest credits made in accordance with the terms of the plan in the column titled ‘‘Non-Equity Incentive Plan Compensation ($).’’ Because the Committee authorized a November 2007 payment of
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Table of Contentsall remaining plan balances to the remaining participants, the amounts reported in the Summary Compensation Table below represent the final interest credits that we will provide to the participants on behalf of this plan.
Originally, awards vested over a five-year period with one-third vesting at the beginning of each of years three, four, and five following the award date. Prior to the enactment of IRC Section 409(A) on January 1, 2005, payments relating to unvested awards earned prior to September 30, 2004 under LTIP-1 were expected to be made annually through the end of fiscal 2011. On November 2, 2005, our Board of Supervisors approved amendments to LTIP-1 for the purpose of IRC Section 409(A) compliance. The principal amendments provided:
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 inclusion 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 credits on behalf of the participants and, from that point on, participants’ benefits have earned only interest credits toward their ultimate retirement benefit.
Each of our named executive officers 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 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 2007, 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.
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Table of ContentsIn order to be competitive with other employers, if certain performance criteria are met, we will provide our employee-participants with a match of up to 6% of their base salary that was contributed to the plan during the calendar year. The following chart shows the performance target criteria that must be met for each level of matching contribution:
Will Receive this Matching
Contribution for the Year 115% or higherFor fiscal 2007, our budgeted 401(k) Plan EBITDA was $171.7 million. Our fiscal 2007 results were such that actual 401(k) Plan EBITDA exceeded 115% of budgeted 401(k) Plan EBITDA. As a result, we shall provide participants with a match equal to 100% of their calendar year 2007 contributions that did not exceed 6% of their total base pay up to the statutory maximum of $15,500. The matching contributions that we will make on behalf of our named executive officers are reported in the column titled ‘‘All Other Compensation ($)’’ in the Summary Compensation Table below.
Non-Qualified Deferred Compensation
We maintain 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 on May 26, 1999 in connection with our Recapitalization. The Compensation Deferral Plan is structured as a rabbi trust. On November 2, 2005, for the purpose of IRC Section 409(A) compliance, our Board of Supervisors approved an amendment to the Compensation Deferral Plan that prohibited any additional deferral elections.
Presently, Mr. Alexander and Mr. Dunn are the only remaining beneficiaries of the Compensation Deferral Plan. In accordance with their deferral elections, the entire corpus of the Compensation Deferral Plan shall be distributed to them during January 2008 and the fair market value of their respective portions of the corpus shall be added to their taxable wage earnings for that calendar year.
Because the Compensation Deferral Plan contains only Common Units, and because the cash distributions that inure to those units are immediately distributed to the beneficiaries, the plan does not provide Mr. Alexander and Mr. Dunn with above market interest; nor do 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, nothing relative to the Compensation Deferral Plan is reported in the Summary Compensation Table below.
Supplemental Executive Retirement Plan
In 1998, we adopted a non-qualified, unfunded supplemental retirement plan known as the Suburban Propane Company Supplemental Executive Retirement Plan (the ‘‘SERP’’). The purpose of the SERP is 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
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Table of ContentsJanuary 1, 2003, the SERP was discontinued with a frozen benefit determined for Mr. Alexander and Mr. Dunn. Provided that the SERP requirements are met, upon retirement Mr. Alexander will receive a monthly benefit of $6,737 and Mr. Dunn will receive a monthly benefit of $373. Because this plan does not provide Mr. Alexander and Mr. Dunn with above market interest credits, nothing relative to 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 $6,249 per year, these benefits are provided on the same basis as are provided to other exempt employees. These benefit plans are offered to attract and retain talented employees and to provide them with competitive benefits.
Other than to Mr. Alexander and Mr. Dunn, in accordance with the terms of their employment agreements (described below), there are no post-termination or other special rights provided to any named executive officer to participate in these benefit programs other than the right to participate in such plans for a fixed period of time following termination of employment as required by law.
The costs of all such benefits incurred on behalf of our named executive officer’s are reported in the column titled ‘‘All Other Compensation ($)’’ in the Summary Compensation Table below.
Perquisites
Perquisites represent a minor component of our executive officers’ compensation. Each of the named executive officers is eligible for tax preparation services, a company-provided vehicle, and an annual physical. The following table summarizes both the value and the utilization of these perquisites by the named executive officers.
Preparation
Services
Provided
VehiclePerquisite-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 executive compensation tax deductible limitations of IRC Section 162(m). Accordingly, none of the compensation paid to our named executive officers is subject to limitation. 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 are 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 409(A) 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
71
Table of Contentsany payment under the Severance Plan subjects a participant to the 20% federal excise tax under IRC Section 409(A), 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.
Employment Agreements
Mr. Alexander, our Chief Executive Officer, and Mr. Dunn, our President, are the only named executive officers, and, indeed, the only executive officers, with whom we have employment agreements. We entered into an employment agreement with Mr. Alexander 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. We entered into an employment agreement that had an effective date of February 1, 2007 with Mr. Dunn on February 5, 2007.
Mr. Alexander’s Employment Agreement had an initial term of three years, and automatically renews for successive one-year periods, unless earlier terminated by us or by Mr. Alexander or otherwise terminated in accordance with the terms of the employment agreement. The employment agreement provides for an annual base salary of $450,000 as of September 30, 2006 and provides Mr. Alexander with the opportunity to earn a cash bonus of up to 100% of base salary based upon the achievement of the same EBITDA-related performance criteria as contained in our annual cash bonus plan described in the section titled ‘‘Annual Cash Bonus Plan’’ above. Under our partnership agreement, the Committee has the authority to grant Mr. Alexander a bonus in excess of 100% if, in accordance with the terms of the annual bonus plan, our other executive officers earn bonuses exceeding their target bonuses for the fiscal year. The Committee exercised this authority in connection with Mr. Alexander’s cash bonus for fiscal 2006 and fiscal 2007. The discretionary component of Mr. Alexander’s fiscal 2007 cash bonus is disclosed in the column titled ‘‘Bonus ($)’’ and the non-discretionary component of Mr. Alexander’s bonus is disclosed in the column titled ‘‘Non-Equity Incentive Plan Compensation ($)’’ in the Summary Compensation Table below.
Mr. Alexander’s employment agreement also provides for the opportunity to participate in benefit plans made available to our other executive officers and our other key employees. We also provide Mr. Alexander with a term life insurance policy with a face amount equal to three times his base salary.
If a change of control (as defined in the ‘‘Change of Control’’ section below) of the Partnership occurs, and within six months prior thereto or at any time subsequent to such change of control, we terminate Mr. Alexander’s employment without cause (as defined in the ‘‘Severance Benefits’’ section below) or if Mr. Alexander resigns with good reason (as defined in the ‘‘Severance Benefits’’ section below) or terminates his employment commencing on the six month anniversary and ending on the twelve month anniversary of such change of control, then Mr. Alexander shall be entitled to:
In situations unconnected to a change of control event, if the Partnership terminates Mr. Alexander’s employment without cause or if Mr. Alexander resigns with good reason, then Mr. Alexander shall be entitled to:
The employment agreement requires that if any payment received by Mr. Alexander is subject to either or both of the 20% excise taxes under IRC Sections 4999 and 409(A), the payment shall be
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Table of Contentsincreased 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 is terminated due to death, disability, without good reason, 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, shall be entitled to earned but unpaid base salary plus his pro-rata cash bonus. If his employment is terminated by the Partnership for cause, he shall be entitled to his earned but unpaid base salary only.
Mr. Dunn’s employment agreement has an initial term of two years commencing on February 1, 2007, the term of which shall 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 Mr. Dunn’s employment agreement provide for an initial annual base salary of $400,000 per year (pro-rated in the case of the Partnership’s 2007 fiscal year and any other partial fiscal year during the term of the employment agreement) 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 that same fiscal year (the ‘‘Maximum Annual Cash Bonus’’). Additionally, Mr. Dunn’s employment agreement permits him to participate in the same benefit plans made available to our other executive officers and other key employees.
If a change of control (as defined in the ‘‘Change of Control’’ section below) of the Partnership occurs and within six months prior thereto or within two years thereafter the Partnership terminates Mr. Dunn’s employment without cause (as defined in the ‘‘Severance Benefits’’ section below) or if Mr. Dunn resigns with good reason (as defined in the ‘‘Severance Benefits’’ section below), then Mr. Dunn shall be entitled to a severance payment equal to the sum of:
In situations unconnected to a change of control event, if the Partnership terminates Mr. Dunn’s employment without cause, or if Mr. Dunn resigns with good reason, then Mr. Dunn shall be entitled to:
The employment agreement requires that if any payment received by Mr. Dunn is subject to either or both of the 20% excise taxes under IRC Sections 4999 and 409(A), the payment shall be 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 is 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, shall be entitled to earned but unpaid base salary plus his pro-rata cash bonus for the fiscal year during which termination occurred. If his employment is terminated by the Partnership for cause, or he resigns without good reason, he shall be entitled to his earned but unpaid base salary only.
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Table of ContentsFor additional information, see the table titled ‘‘Potential Payments Upon Termination’’ below.
Severance Benefits
We believe that, in most cases, employees should be paid reasonable severance benefits. Therefore, it is the general policy of the Committee to provide executive officers and other key employees who are terminated by us without cause or who choose to terminate their employment with us for good reason with a severance payment equal to, at a minimum, one year’s base salary, unless circumstances dictate otherwise. This policy was adopted because it may be difficult for former executive officers and other key employees to find comparable employment within a short period of time. However, depending upon individual facts and circumstances, particularly the severed employee’s tenure with us, the Committee permits us to provide additional severance to severed executive officers and other key employees.
A ‘‘key employee’’ is an employee who has attained a director level pay-grade or higher. ‘‘Cause’’ will be deemed to exist where the individual has been convicted of a crime involving moral turpitude, has stolen from us, has violated his or her non-competition or confidentiality obligations, or has been grossly negligent in fulfillment of his or her responsibilities. ‘‘Good reason’’ generally will exist where an executive officer’s position or compensation has been decreased or where the employee has been required to relocate.
Change of Control
Our executive officers and other key employees have built Suburban Propane Partners, L.P. 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’’). Our Severance Protection Plan covers all executive officers, including the named executive officers, with the exception of our Chief Executive Officer and our President, whose severance provisions are established in their respective employment agreements.
The Severance Protection Plan provides for severance payments between sixty-five to 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. Relative to the overall value of Suburban Propane Partners, L.P., these potential change of control benefits are relatively minor. 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 immediately vest and become distributable to the participants and all outstanding, unvested LTIP-1 and LTIP-2 awards immediately vest and become payable to the participants within thirty days of the change of control event. In particular, all outstanding LTIP-2 grants will vest as if the three-year measurement period for each outstanding grant 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.
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Table of ContentsFor purposes of these benefits, a change of control is deemed to occur, in general, if:
The SERP will terminate effective on the close of business thirty days following the change of control. Mr. Alexander and Mr. Dunn will be deemed to have retired and will have their respective benefits determined as of the date the plan is terminated with payment of their benefits no later than ninety days after the change of control. Each 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:
For additional information pertaining to severance payable to our named executive officers following a change of control-related termination, see the table titled ‘‘Potential Payments Upon Termination’’ below.
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Table of ContentsReport 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 Directors that this Compensation Discussion and Analysis be included in this annual report on Form 10-K for fiscal 2007.
The Compensation Committee:
John Hoyt Stookey, Chairman
John D. Collins
Harold R. Logan, Jr.
Dudley C. Mecum
Jane Swift
ADDITIONAL INFORMATION REGARDING EXECUTIVE COMPENSATION
Summary Compensation Table for Fiscal 2007
The following table sets forth certain information concerning compensation of each named executive officer during the fiscal year ended September 29, 2007:
($)(1)
($)(2)
Awards
($)(3)
Incentive Plan
Compensation
($)(4)
Pension Value
and
Nonqualified
Deferred
Compensation
Earnings
($)(5)
Compensation
($)(6)
($) (a)
Chief Executive Officer
Vice President & CFO
President
Vice President of Operations
Vice President of Human Resources & Admin.
Former Vice President & CIO76
Table of Contents in prior fiscal years. The calculations of the charges to earnings generated by both plans were made in accordance with SFAS 123R. The breakdown for each plan with respect to each named executive officer is as follows:
Because Mr. Plante and Mr. Dunn have met the retirement eligibility criteria under the provisions of both plans, the accounting rules set forth in SFAS 123R require full recognition of all expense relative to such plans on behalf of individuals who need only to choose to retire to trigger the vesting of their awards (4) The amounts reported in this column represent the portions of each named executive officer’s annual cash bonus that were earned in accordance with the performance measures discussed under the subheading ‘‘Annual Cash Bonus Plan’’ in the ‘‘Compensation Discussion and Analysis’’ and the interest credits made on behalf of the remaining LTIP-1 balances. The breakdown for each plan with respect to each named executive officer is as follows:
(5) The amounts reported in this column represent each named executive officer’s Cash Balance Plan earnings for the year. (6) The amounts reported in this column consist of the following:
Note: Column (f) was omitted from the Summary Compensation Table because the Partnership does not award options to its employees.77
Table of ContentsGrants of Plan Based Awards Table for Fiscal 2007
The following table sets forth certain information concerning grants of awards made to each named executive officer during the fiscal year ended September 29, 2007:
Payments Under
Non-Equity
Incentive
Plan Awards
Payments Under
Equity Incentive
Plan Awards
Name
Date
Date
Units
Underlying
Equity
Incentive
Plan
Awards
(LTIP-2)(4)(5)
($)
($)
($)
($)
Other
stock
Awards:
Number
of Shares
of Stock
or Units
(#)
Date
Fair
Value
of Stock
and
Option
Awards
($)(6) (a)78
Table of Contents (3) LTIP-2 is a phantom unit plan. Payments, if earned, are based on a combination of (1) the fair market value of our Common Units at the end of a three-year measurement period, which, for purposes of the plan, is the average of the closing prices for the twenty business days preceding the conclusion of the three-year measurement period, and (2) cash equal to the distributions that would have inured to the same quantity of outstanding Common Units during the same three-year measurement period. The fiscal 2007 award ‘‘Target ($)’’ 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 29, 2007) of our Common Units at the end of fiscal 2007, and (2) the estimated distributions over the course of the award’s three-year measurement period. Column F (‘‘Threshold $’’) was omitted because LTIP-2 does not provide for a minimum cash payment. (4) This column is frequently used when non-equity incentive plan awards are denominated in units; however, in this case, the numbers reported represent the phantom units each named executive officer was awarded under LTIP-2 during fiscal 2007. (5) Mr. Jolly forfeited his fiscal 2007 LTIP-2 award in accordance with the provisions of his severance agreement. (6) The dollar amounts reported in this column represent the aggregate fair value of the RUP awards on the grant date, calculated in accordance with SFAS 123R. The fair value shown may not be indicative of the value realized in the future upon vesting due to the variability in the trading price of our Common Units. Note: Column (k) was omitted from the Grants of Plan Based Awards Table because the Partnership does not award options to its employees.Outstanding Equity Awards at Fiscal Year End 2007 Table
The following table sets forth certain information concerning outstanding equity awards under our 2000 Restricted Unit Plan and phantom equity awards under our 2003 Long-Term Incentive Plan for each named executive officer as of September 29, 2007:
Shares or Units of
Stock That Have
Not Vested
(#)(4)
of Shares or
Units of Stock
That Have Not
Vested
($)(5)
Plan Awards:
Number of
Unearned
Shares, Units or
Other Rights
that Have Not
Vested
(#)(6)
Awards: Market or
Payout Value of
Unearned Shares,
Units or Other Rights
That Have Not Vested
($)(7) (a)79
Table of Contents (2) Mr. Boyd’s RUP awards will vest as follows:
(3) Mr. Keating will meet the retirement eligibility criteria (explained under the subheading ‘‘2003 Long-Term Incentive 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 award, his award will vest as follows:
2007
2008
2009
2010
2010
2011
2012 Quantity of Units
(4) The figures reported in this column represent the total quantity of each of our named executive officer’s unvested RUP awards. (5) 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 28, 2007. (6) The amounts reported in this column represent the quantities of phantom units that underlie the outstanding fiscal 2006 and fiscal 2007 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 contrast to the total return provided by a predetermined peer group of eleven other companies, most of which are publicly-traded partnerships, to their shareholders or unitholders. For more information on LTIP-2, refer to the subheading ‘‘2003 Long-Term Incentive Plan’’ in the ‘‘Compensation Discussion and Analysis.’’ (7) The amounts reported in this column represent the estimated future target payouts of the fiscal 2006 and fiscal 2007 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 29, 2007 (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, actual payments at the end of the three-year measurement period may differ. The following chart provides a breakdown of each year’s awards:
2010
2011
2012 Quantity of Units
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Table of Contents Note: Columns (b), (c), (d), (e) and (f), all of which are for the reporting of option-related compensation, have been omitted from the Outstanding Equity Awards At Fiscal Year End Table because we do not grant options to our employees.Equity Vested Table for Fiscal 2007
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 all vesting of awards under our 2000 Restricted Unit Plan and the vesting of the fiscal 2005 award under our 2003 Long-Term Incentive Plan for each named executive officer during the fiscal year ended September 29, 2007:
Acquired on Vesting (#)
Vesting ($)(1) Mark A. Alexander
Plan – Fiscal 2005(2) Award
Acquired on Vesting (#)
Vesting ($)(3) Mark A. AlexanderPension Benefits Table for Fiscal 2007
The following table sets forth certain information concerning each plan that provides for payments or other benefits at, following, or in connection with retirement for each named executive officer as of the end of the fiscal year ended September 29, 2007:
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Table of Contents
years
Credited
Service
(#)
Accumulated
Benefit ($)
During Last
Fiscal Year
($) Mark A. Alexander82
Table of ContentsPotential Payments Upon Termination
Potential Payments upon Termination to Named Executive Officers with Employment Agreements
The following table sets forth certain information concerning the potential payments to Mr. Alexander and Mr. Dunn under their employment agreements, the SERP and the Long-Term Incentive Plans (‘‘LTIP-1’’ and ‘‘LTIP-2’’) for the circumstances listed in the table assuming a September 29, 2007 termination date:
Termination
Without Cause
by the
Partnership or
by the
Executive for
Good Reason
without a
Change of
Control Event
Termination
Without Cause
by the
Partnership or
by the
Executive for
Good Reason
with a Change
of Control
Event Mark M. Alexander83
Table of Contents normal vesting schedule and will be subject to the same requirements as awards held by individuals still employed by the Partnership and shall be subject to the same risks as awards held by all other participants. (3) The amounts reported on these lines represent the remaining balances of LTIP-1 which, by action of the Committee, were paid to the participants on November 16, 2007. (4) In the event of death, Mr. Alexander’s and Mr. Dunn’s estates are entitled to a payment equal to the decedent’s earned but unpaid salary and pro-rata cash bonus at the time of death. (5) In the event of disability, each is entitled to a payment equal to his earned but unpaid salary and pro-rata cash bonus. (6) Because Mr. Alexander had not attained age 55 on September 30, 2007, if any of the above hypothetical events had occurred on that date, only death, disability or a change in control would give 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 $210,700. 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 $980,400. The figure ($385,900) reported in the table represents the present value of the hypothetical future 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, LTIP-2 and LTIP-1 for the circumstances listed in the table assuming a September 29, 2007 termination date:
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Table of Contents
Termination
Without Cause
by the
Partnership or
by the
Executive for
Good Reason
without a
Change of
Control
Event(8)
Termination
Without Cause
by the
Partnership or
by the
Executive for
Good Reason
with a Change
of Control
Event Robert M. Plante85
Table of ContentsIn 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 shall be subject to the same risks as awards held by all other participants. However, as in the case of Mr. Jolly’s severance agreement, under such circumstances, the rights to such awards are sometimes surrendered by the holder under the terms of the final severance agreement.
(3) The amounts reported on these lines represent the remaining balances of LTIP-1 which, by action of the Committee, was paid to the participants on November 16, 2007. (4) 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. (5) 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. (6) Mr. Plante’s spouse would be entitled to payments of $1,600 per month for 52 months under the Partnership’s predecessor’s Survivor Benefits Plan. The plan provides survivor benefits of up to $1,600 per month to spouses under age 62 and to children under age 18 for up to five years. Because Ms. Plante will attain age 62 within the next five years, if Mr. Plante had died on September 29, 2007, she would have been entitled to 52 payments. This Plan, which was offered by one of the Partnership’s predecessors to all full-time, exempt employees, was closed to additional participants in 1986; however, existing participants were provided with continuing coverage. Mr. Plante is the only executive officer who participates in the plan. (7) The RUP document makes no provisions for the vesting of grants held by recipients who die prior to the completion of the vesting schedule.If a recipient of a RUP grant becomes permanently disabled, only those grants 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 shall immediately vest; all grants held by the recipient for less than one year shall be forfeited by the recipient. Because Mr. Plante’s and Mr. Keating’s RUP grants were awarded less than one year prior to September 29, 2007, if either had become permanently disabled on September 29, 2007, his RUP grant would have been forfeited. Of Mr. Boyd’s 14,596 unvested restricted units as of September 29, 2007, 9,100 would have vested if Mr. Boyd had become permanently disabled on September 29, 2007.
Under circumstances unrelated to a change of control, if a RUP grant recipient’s employment is terminated without cause or he or she resigns for good reason, any RUP grants held by such recipient shall be forfeited.
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Table of ContentsIn the event of a change of control, as defined in the RUP document, all unvested RUP grants shall 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.
(8) Any severance benefits, unrelated to a change-of-control event, payable to these officers would be determined by the Compensation 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.Actual Severance Arrangement with Jeffrey S. Jolly
The following table provides information concerning the Partnership’s severance arrangement with Mr. Jolly whose position was eliminated on January 26, 2007:
Termination
Without Cause
by the
Partnership or
by the
Executive for
Good Reason
without a
Change of
Control Event Cash Compensation(1)87
Table of ContentsSUPERVISORS’ COMPENSATION
The following table sets forth the compensation of the non-employee members of the Board of Supervisors of the Partnership during fiscal 2007.
or Paid in
Cash
($)(1)
($)(4)
incentive plan
compensation
($)
Pension Value
and Nonqualified
Deferred
Compensation
Earnings
($)
Compensation
($)
($) John D. Collins (2)Note: The column for reporting option awards was omitted from the Supervisor’s Compensation Table because the Partnership does not award options to its supervisors or to its employees.
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 supervisors receives an annual cash retainer of $75,000, payable in quarterly installments of $18,750 each.
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Table of ContentsMeeting 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 Restricted Unit Plan. All grants vest in accordance with the provisions of the plan document (see Compensation Discussion and Analysis section titled ‘‘2000 Restricted Unit Plan’’ for description of vesting schedule). Upon vesting, all grants are settled by issuing Common Units; therefore, this plan is accounted for as equity rather than as a liability in the Partnership’s financial statements. During fiscal 2004, Messrs. Logan, Mecum and Stookey were awarded unvested restricted unit plan grants of 8,500 units each; during fiscal 2007, each of them received an additional unvested grant of 3,000 units. Upon commencement of their terms as supervisors in fiscal 2007, Mr. Collins and Ms. Swift each received a grant 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 2007 for each supervisor.
Compensation Committee Interlocks and Insider Participation. None.
89
Table of ContentsThe following table sets forth certain information as of November 20, 2007 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.
Beneficial Ownership
of Class Mark A. Alexander (a) (b) (j)90
Table of Contents Fiscal Year End 2007 Table under Item 11, above. Includes 82,038 Common Units which are held in a brokerage account, where there is a possibility that such Common Units could be pledged as security. (d) As of January 26, 2007, the last day of Mr. Jolly’s employment with the Partnership, and the last day on which the Partnership had access to information about Mr. Jolly’s beneficial ownership of Common Units. (e) Excludes 2,198 unvested restricted units, none of which will vest in the 60-day period following November 20, 2007. Restricted unit grants vest 25%, 25% and 50%, respectively, on the third, fourth and fifth anniversaries of the date of grant and 100% upon a ‘‘change in control’’, as defined in the Partnership’s 2000 Restricted Unit Plan. (f) Excludes 13,396 unvested restricted units, none of which will vest in the 60-day period following November 20, 2007. Restricted unit grants vest 25%, 25% and 50%, respectively, on the third, fourth and fifth anniversaries of the date of grant and 100% upon a ‘‘change in control’’, as defined in the Partnership’s 2000 Restricted Unit Plan. Includes 26,033 Common Units which are held in a brokerage account, where there is a possibility that such Common Units could be pledged as security. (g) Excludes 9,375 unvested restricted units, none of which will vest in the 60-day period following November 20, 2007. Restricted unit grants vest 25%, 25% and 50%, respectively, on the third, fourth and fifth anniversaries of the date of grant and 100% upon a ‘‘change in control’’, as defined in the Partnership’s 2000 Restricted Unit Plan. (h) Excludes 5,496 unvested restricted units, none of which will vest in the 60-day period following November 20, 2007. Restricted unit grants vest 25%, 25% and 50%, respectively, on the third, fourth and fifth anniversaries of the date of grant and 100% upon a ‘‘change in control’’, as defined in the Partnership’s 2000 Restricted Unit Plan. (i) Includes 1,985 unvested restricted units which will vest in the 60-day period following November 20, 2007. Inclusive of the units referred to in footnotes (c), (e), (f), (g) and (h) above, the reported number of units also excludes 120,157 unvested restricted units, none of which will vest in the 60 day period following November 20, 2007, owned by certain executive officers, whose restricted units vest on the same basis as described in footnotes (c), (e), (f), (g) and (h) above. Includes 223,723 Common Units which are held in a brokerage account, where there is a possibility that such Common Units could be pledged as security (inclusive of the units referred to in footnotes (b), (c) and (f) above). (j) Refer to Item 13 of this Annual Report for a description of certain lockup requirements pertaining to the Common Units issued to the General Partner under the GP Exchange Transaction. For Messrs. Alexander and Dunn, includes 1,026,010 and 168,216 Common Units, respectively, subject to a two-year lockup requirement from October 19, 2006.91
Table of ContentsSecurities Authorized for Issuance Under the 2000 Restricted Unit Plan
The following table sets forth certain information, as of September 29, 2007, with respect to the Partnership’s 2000 Restricted Unit Plan, under which Restricted Units of the Partnership, as described in Note 9 to the Consolidated Financial Statements included in this Annual Report, are authorized for issuance.
Units to be issued
upon vesting of
restricted
units
(a)
grant date fair
value per
restricted
unit
(b)
units remaining available for
future issuance under the
2000 Restricted Unit Plan
(excluding securities
reflected in column (a))
(c) Equity compensation plans approved by security holders(1)92
Table of ContentsRelated Party Transactions
Certain Relationships and Related Party Transactions
On October 19, 2006, after receiving the requisite approval of the Common Unitholders, the Partnership, the Operating Partnership and the General Partner consummated the GP Exchange Transaction, 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 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. Immediately thereafter, on October 19, 2006, 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. Pursuant to the Distribution Agreement, on October 19, 2006 the Partnership filed a shelf registration statement with the SEC in order to register the resale by the individual members of the General Partner of the Common Units distributed to them by the General Partner. The Partnership has agreed to maintain the effectiveness of the registration statement for two years after October 19, 2006 (subject to the Board of Supervisors’ right to suspend its use under certain circumstances). Additionally, the Partnership agreed to indemnify the individual members of the General Partner, and the General Partner, against certain liabilities arising from the GP Exchange Transaction and the shelf registration statement, including liabilities that may arise under the securities laws.
The numbers of Common Units distributed to the Chief Executive Officer and each executive officer named in the Summary Compensation Table in Item 11 of this Annual Report, as well as the executive officers as a group following the GP Exchange Transaction were as follows. The then three Supervisors who were not officers of the Partnership received no Common Units in the GP Exchange Transaction.
Received in
the GP
Exchange
Transaction Mark A. Alexander (a)93
Table of ContentsUnder the Distribution Agreement, the then individual members of the General Partner are subject to certain restrictions on the transfer of any of the Common Units distributed to them by the General Partner. Each of Messrs. Alexander and Dunn has agreed not to transfer any of the Common Units received by him in the GP Exchange Transaction for a period of two years from October 19, 2006, except: (i) to a family member, or trust for the benefit of a family member, of such individual who agrees to be bound by the lockup requirement; (ii) with the prior written consent of the Board of Supervisors of the Partnership; (iii) pursuant to a Change of Control (as defined in the Distribution Agreement); (iv) by will or the laws of intestacy to such person’s legal representative, heir or legatee; or (v) if such person is a partnership or corporation or similar entity, a distribution to its partners, stockholders, but subject to the terms of the lockup requirement. All other previous members of the General Partner agreed to not transfer any of the Common Units received by him or her in the GP Exchange Transaction for a period of 90 days following consummation of the GP Exchange Transaction except under the circumstances described in clauses (i) through (v) above. This 90 day lockup period has now expired.
Pursuant to the Partnership Agreement, the General Partner is neither required nor permitted to make any additional capital contributions to the Partnership, and the General Partner may not transfer the retained 784 Common Units nor acquire any additional Common Units. Any transfer by the General Partner of its general partnership interest in the Partnership is subject to the prior approval of the Board of Supervisors of the Partnership, except for a transfer by the General Partner of the entirety of such interest to an affiliate of the General Partner.
Additionally, the Board of Supervisors of the Partnership may, at any time, and for any reason, require the General Partner to transfer its general partnership interest in the Partnership or its Common Units to a designee of the Board of Supervisors. The consideration for the transfer of the general partnership interest in the Partnership shall be nominal. The consideration for the transfer of Common Units by the General Partner shall be the current market price of such Common Units. The Board of Supervisors may also, at any time and for any reason, require any or all of the members of the General Partner to transfer their limited liability company interests in the General Partner to a designee of the Board of Supervisors. The consideration for the transfer of limited liability company interests by the members of the General Partner shall be the product of (i) the member’s percentage interest in the General Partner multiplied by the number of Common Units owned by the General Partner and (ii) the current market price of the Common Units. If any such transfer is pursuant to or in connection with a merger or other transaction involving the Partnership, then the consideration for the Common Units owned by the General Partner shall be the consideration being paid on account of the Common Units in connection with the merger or such other transaction. Such consideration shall be paid in the form of cash or, at the option of the Board of Supervisors, in the form of consideration paid in the merger or other transaction.
The Partnership will continue its past practice of providing tax services to the General Partner at no cost to the General Partner and, in fiscal 2007, paid the cost of external tax return preparation services for the former members of the General Partner which amounted to approximately $55,000.
The firm that served as financial advisor to the General Partner in connection with the GP Exchange Transaction has performed merger, acquisition and general financial advisory services for the Partnership in the past. The Partnership has agreed to retain the firm to continue to provide these services for fiscal 2008 through 2011 for an annual fee of $225,000. The Partnership has also agreed to indemnify the firm against various liabilities arising from its engagement by the Partnership, as well as from its engagement as financial advisor to the General Partner in connection with the GP Exchange Transaction.
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:
94
Table of Contents95
Table of ContentsThe following table sets forth the aggregate fees for services related to fiscal years 2007 and 2006 provided by PricewaterhouseCoopers LLP, our independent registered public accounting firm.
2007
2006 Audit Fees (a)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 2007 and fiscal 2006.
96
Table of ContentsPART IV
See ‘‘Index to Financial Statements’’ set forth on page F-1.
See ‘‘Index to Financial Statement Schedule’’ set forth on page S-1.
See ‘‘Index to Exhibits’’ set forth on page E-1.
97
Table of ContentsSIGNATURES
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.
SupervisorPursuant 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:
Supervisor November 28, 2007
Chief Accounting Officer November 28, 200798
Table of ContentsINDEX TO EXHIBITS
The exhibits listed on this Exhibit Index are filed as part of this Annual Report. Exhibits required to be filed by Item 601 of Regulation S-K, which are not listed below, are not applicable.
NumberE-1
Table of Contents
NumberE-2
Table of Contents
NumberE-3
INDEX TO FINANCIAL STATEMENTS
SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES
F-1
Table of ContentsReport of Independent Registered Public Accounting Firm
To the Board of Supervisors and Unitholders of
Suburban Propane Partners, L.P.:In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, partners’ capital and of cash flows present fairly, in all material respects, the financial position of Suburban Propane Partners, L.P. and its subsidiaries (the ‘‘Partnership’’) at September 29, 2007 and September 30, 2006, and the results of their operations and their cash flows for each of the three years in the period ended September 29, 2007 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 index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set for therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of September 29, 2007, 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 schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing in Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Partnership’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
As discussed in Note 11 to the consolidated financial statements, the Partnership changed its method of accounting for its defined benefit pension and postretirement plans effective September 29, 2007.
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 28, 2007F-2
Table of ContentsSUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands)
2007
2006 ASSETSThe accompanying notes are an integral part of these consolidated financial statements.
F-3
Table of ContentsSUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per unit amounts)
2007
2006
2005 RevenuesThe accompanying notes are an integral part of these consolidated financial statements.
F-4
Table of ContentsSUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
2007
2006
2005 Cash flows from operating activities:The accompanying notes are an integral part of these consolidated financial statements.
F-5
Table of ContentsSUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(in thousands)
Common
Units
Unitholders
Partner
Compen-
sation
Units
Held in
Trust
Compen-
sation
Other
Compre-
hensive
(Loss)
Income
Partners’
Capital
hensive
Income
(Loss) Balance at September 25, 2004
on cash flow hedges into earnings
Restricted Unit Plan
Unit Plan, net of forfeitures
Unit Plan, net of forfeitures
cash flow hedges into earnings
Restricted Unit Plan
from adoption of SFAS 123R
Restricted Unit Plan, net of forfeitures
cash flow hedges into earnings
Restricted Unit Plan
Restricted Unit Plan, net of forfeituresThe accompanying notes are an integral part of these consolidated financial statements.
F-6
Table of ContentsSUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands, except per unit amounts)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, ventilation and air conditioning (‘‘HVAC’’). The publicly traded limited partner interests in the Partnership are evidenced by common units traded on the New York Stock Exchange (‘‘Common Units’’), with 32,674,255 Common Units outstanding at September 29, 2007. 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 of the five members of 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.
On January 5, 2001, Suburban Holdings, Inc., a subsidiary of the Operating Partnership, was formed to hold the stock of Gas Connection, Inc. (d/b/a HomeTown Hearth & Grill), Suburban @ Home, Inc. (‘‘Suburban @ Home’’) and Suburban Franchising, Inc. (‘‘Suburban Franchising’’). On December 31, 2006, Suburban Holdings, Inc. and Suburban @ Home merged into the Service Company. On January 1, 2007, HomeTown Hearth & Grill and Suburban Franchising converted into single-member LLCs owned by the Service Company. HomeTown Hearth & Grill sells and installs natural gas and propane gas grills, fireplaces and related accessories and supplies. Suburban Franchising creates and develops propane related franchising business opportunities.
F-7
Table of ContentsOn December 23, 2003, 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’’) pursuant to an asset purchase agreement dated November 10, 2003 (the ‘‘Agway Acquisition’’). Agway Energy was a leading regional marketer of propane, fuel oil, gasoline and diesel fuel primarily in New York, Pennsylvania, New Jersey and Vermont. To complement its core marketing and delivery business, Agway Energy also installed and serviced a wide variety of home comfort equipment, particularly in the areas of HVAC. The Agway Acquisition was consistent with the Partnership’s business strategy of prudently pursuing acquisitions of retail propane distributors and other energy-related businesses that can complement or supplement its core propane operations. The Agway Acquisition also expanded the Partnership’s presence in the northeast energy market.
On November 21, 2003, Suburban Heating Oil Partners, LLC, a subsidiary of HomeTown Hearth & Grill, was formed to acquire the assets of and operate the fuel oil and refined fuels and HVAC businesses of Agway Energy acquired on December 23, 2003. In addition, Agway Energy Services, LLC, also a subsidiary of HomeTown Hearth & Grill, was formed to acquire and operate the natural gas and electricity marketing business of Agway Energy.
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 (see Note 8).
The Partnership serves approximately 1,000,000 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 2007, 2006 or 2005. During fiscal 2007, 2006 and 2005, three suppliers provided approximately 34%, 35% and 33%, respectively, of the Partnership’s total domestic 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.
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. Fiscal 2006 included 53 weeks of operations compared to 52 weeks in fiscal 2007 and fiscal 2005.
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 HVAC 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, plus an amount for natural gas and electricity delivered but unbilled at the end of each accounting period.
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 management in the areas of self-insurance and litigation reserves, pension and other postretirement benefit liabilities and costs, valuation of
F-8
Table of Contentsderivative 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 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.
Commodity Price Risk. The Partnership enters into a combination of exchange-traded futures and option contracts, forward contracts and, in certain instances, over-the-counter options (collectively, ‘‘derivative instruments’’) to manage the price risk associated with future purchases of the commodities used in its operations, principally propane and fuel oil, as well as to ensure supply during periods of high demand. All of the Partnership’s derivative instruments are reported on the consolidated balance sheet, within other current assets or other current liabilities, at their fair values pursuant to Statement of Financial Accounting Standards (‘‘SFAS’’) No. 133, ‘‘Accounting for Derivative Instruments and Hedging Activities,’’ as amended by SFAS Nos. 137, 138, 149 and 155 (‘‘SFAS 133’’). 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, under SFAS 133, qualify for and are designated as a normal purchase or normal sale contract. Such contracts are exempted from the fair value accounting requirements of SFAS 133 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, 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 a 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 under SFAS 133, are recorded within cost of products sold as they occur.
Interest Rate Risk. A portion of the Partnership’s long-term borrowings bear interest at a variable rate based upon either LIBOR or Wachovia National Bank’s prime rate, plus an applicable margin depending on the level of the Partnership’s total leverage. 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. On March 31, 2005, the Partnership entered into a $125,000 interest rate swap contract in conjunction with the Term Loan facility under the Revolving Credit Agreement (see Note 8). The interest rate swap is being accounted for under SFAS 133 and the Partnership has designated the interest rate swap as a cash flow hedge. Changes in the fair value of the interest rate swap are recognized in OCI until the hedged item is recognized in earnings.
F-9
Table of ContentsLong-Lived Assets. Long-lived assets include:
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:
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 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 non-compete agreements and acquired leasehold interests, customer lists and tradenames. Non-compete agreements are amortized under the straight-line method over the periods of the related agreements, ending periodically between fiscal years 2008 and 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. 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.
Accrued Insurance. Accrued insurance represents the estimated costs of known and anticipated or unasserted claims under the Partnership’s general and product, workers’ compensation and
F-10
Table of Contentsautomobile insurance policies. 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 self-insurance 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 wherein our 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 self-insurance liability that exceeds insurance deductibles, the Partnership records an asset within other assets 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.
Environmental Reserves. The Partnership establishes reserves for environmental exposures when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated based upon the Partnership’s best estimate of costs associated with environmental remediation and ongoing monitoring activities. Accrued environmental reserves are exclusive of claims against third parties, and an asset is established where contribution or reimbursement from such third parties has been agreed and the Partnership is reasonably assured of receiving such contribution or reimbursement. Environmental reserves are not discounted.
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 (the ‘‘Corporate Entities’’). For federal income tax purposes, as well as for state income tax purposes in the majority of the states in which the Partnership operates, the earnings attributable to the Partnership and the Operating Partnership are included in the tax returns of the individual partners. 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. SFAS No. 143, ‘‘Accounting for Asset Retirement Obligations,’’ (‘‘SFAS 143’’) and Financial Accounting Standards Board (‘‘FASB’’) Interpretation No. 47, ‘‘Accounting for Conditional Asset Retirement Obligations’’ (‘‘FIN 47’’) prescribes financial accounting and reporting standards for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The provisions of this statement 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 of contractually mandated removal of leasehold improvements and certain costs to remove and properly dispose of underground and aboveground fuel oil storage tanks.
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,
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Table of Contentsconstructed or leased. The Partnership records the liability, which is referred to as an asset retirement obligation, when it has a legal obligation, as defined in SFAS 143, 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 accounts for unit-based compensation in accordance with the revised SFAS No. 123, ‘‘Share-Based Payment’’ (‘‘SFAS 123R’’) which was adopted by the Partnership effective for the quarter ended December 24, 2005, the first quarter of fiscal 2006. Prior to adoption, the Partnership accounted for unit-based compensation plans under the provisions of Accounting Principles Board Opinion No. 25, ‘‘Accounting for Stock Issued to Employees,’’ and related interpretations and followed the disclosure only provision of SFAS No. 123, ‘‘Accounting for Stock-Based Compensation’’. SFAS 123R requires the recognition of 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. SFAS 123R also requires the measurement of liability awards under an equity-based payment arrangement based on remeasurement of the award’s fair value at the conclusion of each quarterly 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 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 earnings per Common Unit are performed in accordance with SFAS No. 128 ‘‘Earnings per Share’’ (‘‘SFAS 128’’). Prior to the GP Exchange Transaction, when the General Partner owned IDRs in the Partnership, computations of earnings per Common Unit were performed in accordance with Emerging Issues Task Force (‘‘EITF’’) consensus 03-6 ‘‘Participating Securities and the Two-Class Method Under FAS 128’’ (‘‘EITF 03-6’’), when applicable. EITF 03-6 requires, among other things, the use of the two-class method of computing earnings per unit when participating securities exist. 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
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Table of Contentsallocated 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.
Basic income per Common Unit for the year ended September 29, 2007 is computed by dividing net income by the weighted average number of outstanding Common Units. Diluted income per Common Unit for the year ended September 29, 2007 is computed by dividing net income by the weighted average number of outstanding Common Units and unvested Restricted Units granted under the 2000 Restricted Unit Plan.
Basic income per Common Unit for the year ended September 30, 2006 was computed by dividing the limited partners’ share of net income, calculated under the two-class method of computing earnings, by the weighted average number of outstanding Common Units. Net income was allocated to the Unitholders and the General Partner in accordance with their respective partnership ownership interests, after giving effect to any priority income allocations to the General Partner for IDRs. Following the GP Exchange Transaction consummated on October 19, 2006, the two-class method of computing income per Common Unit under EITF 03-6 is no longer applicable.
Basic net income (loss) per Common Unit for the years ended September 30, 2006 and September 24, 2005 was computed by dividing net income (loss), after deducting the General Partner’s interest, by the weighted average number of outstanding Common Units. Diluted net income (loss) per Common Unit for these same periods is computed by dividing net income (loss), after deducting the General Partner’s interest, by the weighted average number of outstanding Common Units and unvested Restricted Units granted under the Partnership’s 2000 Restricted Unit Plan. In computing diluted net income per Common Unit, weighted average units outstanding used to compute basic net income per Common Unit were increased by 175,701 and 143,039 units for the years ended September 29, 2007 and September 30, 2006, respectively, to reflect the potential dilutive effect of the unvested Restricted Units outstanding using the treasury stock method. Diluted net income per Common Unit for the year ended September 24, 2005 does not include 134,471 Restricted Units as their effect would be anti-dilutive.
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 (prior to the adoption of SFAS No. 158, ‘‘Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – An Amendment of FASB Statements No. 87, 88, 103 and 132R’’ (‘‘SFAS 158’’)) and changes in the funded status of the pension plan (subsequent to the adoption of SFAS 158).
Recently Issued Accounting Standards. In February 2007, the Financial Accounting Standards Board (‘‘FASB’’) issued SFAS No. 159, ‘‘The Fair Value Option for Financial Assets and Financial Liabilities’’ (‘‘SFAS 159’’). Under SFAS 159, entities may elect to measure specified financial instruments and warranty and insurance contracts at fair value on a contract-by-contract basis, with changes in fair value recognized in earnings each reporting period. SFAS 159 is effective for fiscal years beginning after November 15, 2007, which will be the Partnership’s 2009 fiscal year beginning September 28, 2008. The Partnership is currently in the process of evaluating the impact that SFAS 159 may have on its consolidated financial position, results of operations and cash flows.
In September 2006, the FASB issued SFAS No. 157, ‘‘Fair Value Measurements’’ (‘‘SFAS 157’’). SFAS 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. It also establishes a fair value hierarchy that prioritizes information used in developing assumptions when pricing an asset or liability. Like SFAS 159 above, SFAS 157 will be effective for fiscal years beginning after November 15, 2007, which will be the Partnership’s 2009 fiscal year beginning September 28, 2008. The Partnership is currently in the process of evaluating the impact that SFAS 157 may have on its consolidated financial position, results of operations and cash flows.
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Table of ContentsIn June 2006, the FASB issued FASB Interpretation No. 48, ‘‘Accounting for Uncertainty in Income Taxes – An Interpretation of FASB Statement No. 109’’ (‘‘FIN 48’’). FIN 48 requires companies to determine whether it is more likely than not that a tax position will be sustained upon examination by the appropriate taxing authorities before any part of the benefit can be recorded in the financial statements. FIN 48 is effective for fiscal years beginning after December 15, 2006, which will be the Partnership’s 2008 fiscal year beginning September 30, 2007. The Partnership is currently in the process of assessing the impact that FIN 48 will have on its consolidated financial statements and currently does not expect that adoption of FIN 48 will have a material impact on its financial position, results of operation or cash flows.
Reclassifications. Certain prior period amounts have been reclassified to conform with the current period presentation.
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.
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 29, 2007:
2007
2006
2005 First QuarterOn October 25, 2007, the Board of Supervisors declared a quarterly distribution of $0.75 per Common Unit, or $3.00 per Common Unit on an annualized basis, in respect of the fourth quarter of fiscal 2007, which was paid on November 13, 2007 to holders of record on November 6, 2007. This quarterly distribution included an increase of $0.0375 per Common Unit, or $0.15 per Common Unit on an annualized basis, from the previous distribution rate.
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Table of ContentsInventories consist of the following:
2007
2006 Propane and refined fuelsDuring fiscal 2006, the Partnership recorded a charge of $3,517 to reduce the carrying value of appliance and parts inventory that would no longer be actively marketed by its customer service centers.
The Partnership enters into contracts to buy propane, fuel oil and natural gas for supply purposes. Such contracts generally have one year terms subject to annual renewal, with costs based on market prices at the date of delivery.
Property, plant and equipment consist of the following:
2007
2006 Land and improvementsDepreciation expense from continuing operations for the years ended September 29, 2007, September 30, 2006 and September 24, 2005 amounted to $26,547, $30,066 and $32,363, respectively. Depreciation expense for the years ended September 30, 2006 and September 24, 2005 included non-cash charges of $1,094 and $425, respectively, related to an impairment of assets as a result of restructuring activities in each of those years (see Note 6). Depreciation expense from discontinued operations for the years ended September 29, 2007, September 30, 2006 and September 24, 2005 amounted to $452, $498 and $502, respectively.
The Partnership’s fiscal 2007 and fiscal 2006 annual goodwill impairment review resulted in no adjustments to the carrying amount of goodwill. Based on the results of its fiscal 2005 annual goodwill impairment review, the Partnership recorded a non-cash charge of $656 for the impairment of goodwill associated with its HVAC segment for the year ended September 24, 2005. During fiscal 2007, the Partnership reversed $3,800 of the deferred tax asset valuation allowance, 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.
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Table of ContentsOther intangible assets, the majority of which were acquired in the Agway Acquisition, consist of the following:
2007
2006 Customer listsDuring 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 relinquished assets with a fair value of approximately $4,000 and allocated this fair value among the assets received, including $2,450 to the customer list acquired and $1,550 to the property, plant and equipment acquired (primarily tanks and cylinders). This customer list will be amortized over a ten-year period. 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.
Aggregate amortization expense related to other intangible assets for the years ended September 29, 2007, September 30, 2006 and September 24, 2005 was $2,243, $2,587 and $4,897, respectively. Amortization expense for the year ended September 24, 2005 included a non-cash charge of $810 attributable to an impairment in the value of tradenames associated with the HVAC segment which were acquired in the Agway Acquisition. Aggregate amortization expense related to other intangible assets for each of the five succeeding fiscal years as of September 29, 2007 is as follows: 2008 – $2,224; 2009 – $2,220; 2010 – $2,205; 2011 – $2,205 and 2012 - $1,730.
During the fourth quarter of fiscal 2005 and throughout fiscal 2006, the Partnership approved and initiated plans of reorganization to realign the field operations in an effort to streamline the operating footprint and to leverage the system infrastructure to achieve additional operational efficiencies and reduce costs, as well as to restructure its HVAC business (collectively, the ‘‘Restructuring’’). As a result of the Restructuring, the Partnership recorded a restructuring charge of $2,775 during fiscal 2005 associated with severance and other employee benefits for approximately 85 positions eliminated and in fiscal 2006 recorded additional charges of $5,276 related to severance and other employee benefits for approximately 325 positions eliminated and $800 related to exit costs, primarily lease termination costs, associated with a plan to exit certain activities of the HomeTown Hearth & Grill business. During fiscal 2007, payments for severance and other employee costs associated with the Restructuring totaled $1,621 and were charged against the reserves established. As of September 29, 2007, the reserve for severance and other employee benefits has been fully utilized. The remaining reserve consists only of exit costs associated with the HomeTown Hearth & Grill business, which amounted to $370 and is expected to be utilized over the next twelve months.
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.
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Table of ContentsFor 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 HVAC 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 such, at present many of those entities do not report a tax provision as a result of the full valuation allowance.
Although the corporate entities are subject to corporate level income tax, management has conducted a review of the need for a valuation allowance and believes, based upon an analysis of both negative and positive evidence, at the balance sheet date, that it is more likely than not that the Partnership’s deferred tax assets will not be utilized in the future. Therefore, management has determined that for the year ended September 29, 2007, it is necessary to maintain the offsetting valuation allowance. 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. In order to reach a more likely than not conclusion that the deferred tax assets will be utilized, management believes that it will be necessary to assess the performance of fiscal 2008 with the performance of the preceding quarters to determine if a more likely than not conclusion can be reached. Because of the trend of taxable operating results for the corporate entities has been improving over the past two years, management believes a reasonable possibility exists that, within the next year, sufficient positive evidence may be available to reach a conclusion that a valuation allowance is no longer needed.
The income tax provision (benefit) of all the legal entities included in the Partnership’s consolidated statement of operations consists of the following:
2007
2006
2005 CurrentAs a result of the profitability of the Partnership’s fuel oil and refined fuel business, 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 $3,800 deferred tax provision, and a corresponding reversal of a portion of the valuation allowance established in purchase accounting for the Agway Acquisition, which reduced goodwill (see Note 5).
The federal income tax benefits reported for fiscal 2005 result from a refund of prior taxes paid.
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Table of ContentsThe provision for income taxes differs from income taxes computed at the United States federal statutory rate as a result of the following:
2007
2006
2005 Income tax provision at federal statutory tax rateThe components of net deferred taxes and the related valuation allowance using current enacted tax rates are as follows:
2007
2006 Deferred tax assets:In order to fully realize the net deferred tax assets, the corporate entities will need to generate future taxable income. A valuation allowance is provided when it is more likely than not that some portion or all of the deferred tax assets will not be realized. Although certain corporate entities generated taxable income during fiscal 2007, based upon the level of current taxable income and projections of future taxable income of the corporate entities over the periods which deferred tax assets are expected to be deductible, management believes that it is more likely than not that the Partnership will not realize the full benefit of its deferred tax assets as of September 29, 2007 and September 30, 2006. Of the total valuation allowance as of September 29, 2007, $17,719 was established through purchase accounting for the Agway Acquisition in December 2003. To the extent that a reversal of a portion of the valuation allowance is warranted in the future, the reversal will be
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Table of Contentsrecorded as a reduction of goodwill. During fiscal 2007, $8,820 of the Partnership’s net operating loss-related deferred tax benefits were realized, of which $3,800 resulted in a reversal of valuation allowance with a corresponding reduction to goodwill.
As of September 29, 2007, the Partnership had tax loss carryforwards for federal income tax reporting purposes of approximately $86,760 which are available to offset future federal taxable income and expire between 2024 and 2026.
Short-term and long-term borrowings consist of the following:
2007
2006 Senior Notes, 6.875%, due December 15, 2013, net of unamortized discount of $1,462 and $1,696, respectivelyThe 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%. 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 2003 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 on or after December 15, 2008 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 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.
The Operating Partnership has a revolving credit facility, the Third Amended and Restated Credit Agreement (the ‘‘Revolving Credit Agreement’’), which expires on March 31, 2010. The Revolving Credit Agreement provides for a five-year $125,000 term loan facility (the ‘‘Term Loan’’) and a separate working capital facility which provides available revolving borrowing capacity up to $175,000. In addition, under the third amendment to the Revolving Credit Agreement the Operating Partnership is authorized to incur additional indebtedness of up to $10,000 in connection with capital leases and up to $20,000 in short-term borrowings during the period from December 1 to April 1 in each fiscal year to provide additional working capital during periods of peak demand, if necessary.
Borrowings under the Revolving Credit Agreement, including the Term Loan, bear interest at a rate based upon either LIBOR or Wachovia National Bank’s prime rate, plus, in each case, the applicable margin or the Federal Funds rate plus 1/2 of 1%. An annual facility fee ranging from 0.375% to 0.50%, based upon certain financial tests, is payable quarterly whether or not borrowings occur. As of September 29, 2007 and September 30, 2006, there were no borrowings outstanding under the working capital facility of the Revolving Credit Agreement and there have been no borrowings since April 2006.
In connection with the Term Loan, the Operating Partnership also entered into an interest rate swap agreement with a notional amount of $125,000. Effective March 31, 2005 through March 31, 2010, the Operating Partnership will pay a fixed interest rate of 4.66% to the issuing lender on notional principal amount of $125,000, 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. The applicable margin above LIBOR, as defined in the Revolving Credit Agreement, will be paid in addition to this fixed interest rate of 4.66%. The fair
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Table of Contentsvalue of the interest rate swap amounted to $(284) and $1,182 at September 29, 2007 and September 30, 2006, respectively, and is included in other liabilities and other assets, respectively, with a corresponding amount included within OCI.
The Revolving Credit Agreement 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. Under the Revolving Credit Agreement, the Operating Partnership is required to maintain a leverage ratio (the ratio of total debt to EBITDA) of less than 4.0 to 1. In addition, the Operating Partnership is required to maintain an interest coverage ratio (the ratio of EBITDA to interest expense) of greater than 2.5 to 1 at the Partnership level. The Partnership and the Operating Partnership were in compliance with all covenants and terms of the 2003 Senior Notes and the Revolving Credit Agreement as of September 29, 2007.
Debt origination costs representing the costs incurred in connection with the placement of, and the subsequent amendment to, the 2003 Senior Notes and the Revolving Credit Agreement were capitalized within other assets and are being amortized on a straight-line basis over the term of the respective debt agreements. Other assets at September 29, 2007 and September 30, 2006 include debt origination costs with a net carrying amount of $6,230 and $7,557, respectively. Aggregate amortization expense related to deferred debt origination costs included within interest expense for the years ended September 29, 2007, September 30, 2006 and September 24, 2005 was $1,327, $1,324 and $1,514, respectively.
The aggregate amounts of long-term debt maturities subsequent to September 29, 2007 are as follows: 2008 – $0; 2009 – $0; 2010 – $125,000; 2011 – $0; and, thereafter-$425,000.
As described in Note 2, the Partnership accounts for its unit-based compensation arrangements under SFAS 123R which requires the recognition of 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, as well as the measurement of liability awards under a unit-based payment arrangement based on remeasurement of the award’s fair value at the conclusion of each quarterly 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 2000 Restricted Unit Plan 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 consistent with the requirements of SFAS 123R.
2000 Restricted Unit Plan. In November 2000, the Partnership adopted the Suburban Propane Partners, L.P. 2000 Restricted Unit Plan (the ‘‘2000 Restricted Unit Plan’’) which authorizes the issuance of Common Units to executives, managers and other employees and members of the Board of Supervisors of the Partnership. On October 17, 2006, the Partnership adopted amendments to the 2000 Restricted Unit Plan which, among other things, increased the number of Common Units authorized for issuance under the plan by 230,000 for a total of 717,805. Restricted Units issued under the 2000 Restricted Unit Plan 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 2000 Restricted Unit Plan participants are not eligible to receive quarterly distributions or vote their respective Restricted Units until vested. Restrictions also limit the sale or transfer of the units during the restricted periods. The value of the Restricted Unit is established by the market price of the Common Unit on the date of grant. Restricted Units are subject to forfeiture in certain circumstances as defined in the 2000 Restricted Unit Plan. Compensation expense for the unvested awards is recognized ratably over the vesting periods and is net of estimated forfeitures.
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Table of ContentsFollowing is a summary of activity in the 2000 Restricted Unit Plan:
Grant Date
Fair Value Per Unit Outstanding September 25, 2004As of September 29, 2007, unrecognized compensation cost related to unvested Restricted Units awarded under the 2000 Restricted Unit Plan amounted to $7,094. Compensation cost associated with the unvested awards is expected to be recognized over a weighted-average period of 2.1 years. Compensation expense for the 2000 Restricted Unit Plan for years ended September 29, 2007, September 30, 2006 and September 24, 2005 was $3,014, $2,221 and $1,806, 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 primarily composed of other Master Limited Partnerships, approved by the Compensation Committee of the Board of Supervisors, over the same three-year performance period. Compensation expense for the years ended September 29, 2007 and September 30, 2006 was $5,977 and $1,249, respectively. As a result of the performance at the end of fiscal 2005, the Partnership recorded a reversal of compensation expense in the amount of ($644) for the year ended September 24, 2005.
In 1996, the Partnership adopted the 1996 Restricted Unit Award Plan (the ‘‘1996 Restricted Unit Plan’’) which authorized the issuance of Common Units with an aggregate value of $15,000 (731,707 Common Units valued at the initial public offering price of $20.50 per unit) to executives, managers and non-employee Supervisors of the Partnership. According to the change of control provisions of the 1996 Restricted Unit Plan, all outstanding Restricted Units on the closing date of the recapitalization in May 1999 vested and converted into Common Units. At the date of the recapitalization, individuals who became members of the General Partner surrendered receipt of 553,896 Common Units, representing substantially all of their vested Restricted Units, in exchange for the right to participate in the Compensation Deferral Plan.
Effective May 26, 1999, in connection with the Partnership’s recapitalization, the Partnership adopted the Compensation Deferral Plan (the ‘‘Deferral Plan’’) which provided for eligible employees of the Partnership to defer receipt of all or a portion of the vested Restricted Units granted under the 1996 Restricted Unit Plan in exchange for the right to participate in and receive certain payments under the Deferral Plan. Senior management of the Partnership surrendered 553,896 Common Units, at the date of the recapitalization, into the Deferral Plan. The Partnership deposited into a trust on behalf of these individuals 553,896 Common Units. During fiscal 2000, certain members of
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Table of Contentsmanagement deferred receipt of an additional 42,925 Common Units granted under the Deferral Plan, with a fair value of $19.91 per Common Unit at the date of grant, by depositing the units into the trust.
In January 2003, in accordance with the terms of the Deferral Plan, 297,310 of the deferred units were distributed to certain members of the General Partner and became freely traded, while the remaining members of management elected to further defer receipt of their deferred units (totaling 299,511 Common Units) until a later date through January 2008. In November 2004, an additional 3,272 Common Units with a fair value of $109 were deposited into the Deferral Plan on behalf of individuals electing to defer receipt of Common Units vested under the 2000 Restricted Unit Plan. On November 2, 2005, the Deferral Plan was amended to disallow any additional deferrals of Common Units into the trust subsequent to December 31, 2004.
During fiscal 2007, 2,195 Common Units were distributed from the Deferral Plan, resulting in a reduction of $44 in the deferred compensation liability and a corresponding reduction in the value of Common Units held in trust, both within partners’ capital.
As of September 29, 2007 and September 30, 2006, there were 292,682 and 294,877 Common Units, respectively, held in trust under the Deferral Plan. The value of the Common Units deposited in the trust and the related deferred compensation obligation in the amount of $5,660 and $5,704 as of September 29, 2007 and September 30, 2006, respectively, are reflected in the accompanying consolidated balance sheets as components of partners’ capital.
Defined Contribution Plan. The Partnership has an employee Retirement Savings and Investment Plan (the ‘‘401(k) Plan’’) covering most employees. Employer contributions and costs relating to the 401(k) Plan are a percent of the participating employees’ compensation, subject to the achievement of annual performance targets of the Partnership. These contributions totaled $5,426, $3,868 and $183 for the years ended September 29, 2007, September 30, 2006 and September 24, 2005, respectively.
Defined Benefit Pension Benefits and Retiree Health and Life Benefits.
Defined Benefit Pension Benefits. The Partnership has a noncontributory defined benefit pension plan which was originally designed to cover all eligible employees of the Partnership who met certain requirements as to age and length of service. Effective January 1, 1998, the Partnership amended its noncontributory 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 noncontributory defined benefit pension plan was limited to eligible participants in existence 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. The trust’s assets consist primarily of fixed income securities. 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 which may be determined from time to time. There were no minimum funding requirements for the defined benefit pension plan for fiscal 2007, 2006 or 2005. 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 recently 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 and
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Table of Contentsthat retired prior to March 1998 are eligible for such benefits if they reached a specified retirement age while working for the Partnership. Effective January 1, 2000, the Partnership terminated its postretirement benefit plan for all eligible employees retiring after March 1, 1998. All active and eligible employees who were eligible to receive benefits under the postretirement plan subsequent to March 1, 1998, were provided an increase to their accumulated benefits under the cash balance pension plan. The Partnership’s postretirement health care and life insurance benefit plans are unfunded. Effective January 1, 2006, the Partnership changed its postretirement health care plan from a self-insured program to one that is fully insured under which the Partnership pays a portion of the insurance premium on behalf of the eligible participants. This modification to the postretirement health care plan reduced the accumulated benefit obligation as of September 30, 2006 by $5,133 and resulted in a reduction of the net periodic postretirement benefit expense by approximately $637 for the year ended September 30, 2006.
In September 2006, the FASB issued SFAS No. 158, ‘‘Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – An Amendment of FASB Statements No. 87, 88, 103 and 132R’’ (‘‘SFAS 158’’). SFAS 158 requires companies to recognize the funded status of pension and other postretirement benefit plans as an asset or liability on sponsoring employers’ balance sheets and to recognize changes in the funded status in comprehensive income (loss) in the year the changes occur. This statement also requires the measurement date of plan assets and obligations to occur at the end of the employer’s fiscal year. The Partnership uses the date of its consolidated financial statements as the measurement date.
The initial impact of adopting the standard is to recognize in accumulated other comprehensive income (loss) unrecognized prior service costs or credits and net actuarial gains or losses that were previously unrecognized under SFAS No. 87, ‘‘Employers’ Accounting for Pension’’ (‘‘SFAS 87’’). SFAS 158 became effective for the Partnership’s fiscal year ended September 29, 2007. 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 SFAS 158, as well as the initial impact of the adoption of SFAS 158. The AML under SFAS 87 was eliminated during fiscal 2007, primarily as a result of employer contributions. As of September 29, 2007, the fair value of plan assets exceeded the accumulated benefit obligation of the defined benefit pension plan.
SFAS 158
Adjustments
Prior to
SFAS 158 Adoption
Adoption
SFAS 158
Adjustments Accrued pension liability (asset)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 29, 2007 and September 30, 2006 and a statement of the funded status for both years using an end of year measurement date. Under the Partnership’s defined benefit pension plan, the accumulated benefit obligation and the projected benefit obligation are the same.
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Table of Contents
Benefits
sheets consist of:The AML included in accumulated other comprehensive loss as of September 30, 2006 was $66,778. The amounts in accumulated other comprehensive loss as of September 29, 2007 that are expected to be recognized as components of net periodic benefit costs during the next fiscal year are $3,375 and $490 for pension and postretirement benefits, respectively.
During fiscal 2007 and 2006, lump sum benefit payments to either terminated or retired individuals amounted to $10,786 and $11,521, respectively. The lump sum benefit payments exceeded the combined service and interest costs of the net periodic pension cost of $8,905 and $9,146 for fiscal 2007 and 2006, respectively, and as a result, the Partnership was required to recognize a non-cash settlement charge of $3,269 and $4,437 during the fourth quarter of fiscal 2007 and 2006, respectively, pursuant to SFAS No. 88 ‘‘Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits’’. The non-cash charges were required to accelerate recognition of a portion of cumulative unrecognized losses in the defined benefit pension plan.
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Table of ContentsThe Partnership made voluntary contributions of $25,000 and $10,000 to the defined benefit pension plan during fiscal 2007 and 2006, respectively, thereby taking proactive steps to improve the funded status of the plan. As of September 29, 2007, the fair value of plan assets exceeded the projected benefit obligation of the defined benefit pension plan by $5,547, which was recognized on the balance sheet as an asset.
Plan Asset Allocation. The following table presents the actual allocation of assets held in trust:
2007
2006 Fixed income securities – long-term bondsThe 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 fully fund 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 the $25,000 voluntary contribution described above, 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 85%; and (ii) equity securities portion of the portfolio should range between 15% and 25%.
Projected Contributions and Benefit Payments. There are no projected minimum funding requirements under the Partnership’s defined benefit pension plan for fiscal 2008. The Partnership estimates that retiree health and life benefit payments will be $2,233 for fiscal 2008. Estimated future benefit payments for both pension and retiree health and life benefits are as follows:
Benefits
and Life Benefits 2008Effect on Operations. The following table provides the components of net periodic benefit costs included in operating expenses for the years ended September 29, 2007, September 30, 2006 and September 24, 2005:
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Table of ContentsActuarial Assumptions. The assumptions used in the measurement of the Partnership’s benefit obligations as of September 29, 2007 and September 30, 2006 are shown in the following table:
Life BenefitsThe assumptions used in the measurement of net periodic pension benefit and postretirement benefit costs for the years ended September 29, 2007, September 30, 2006 and September 24, 2005 are shown in the following table:
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 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 10.00% increase in health care costs assumed at September 29, 2007 is assumed to decrease gradually to 5.00% in fiscal 2013 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 29, 2007 by approximately $500 and the aggregate of service and interest components of net periodic postretirement benefit expense for the year ended September 29, 2007 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 29, 2007 by approximately $454 and the aggregate of service and interest components of net periodic postretirement benefit expense for the year ended September 29, 2007 by approximately $26. The Partnership has concluded that the prescription drug benefits within the retiree medical plan will not qualify for a Medicare subsidy available under recent legislation.
Derivative Instruments and Hedging Activities. The Partnership purchases propane and refined fuels that are eventually sold to its customers at various times, quantities and prices, exposing the Partnership to market fluctuations in the price of these commodities. A control environment has been established which includes policies and procedures for risk assessment and the approval, reporting and monitoring of derivative instruments and hedging activities. The Partnership closely monitors the potential impacts of commodity price changes and, where appropriate, utilizes commodity futures, forward and option contracts to hedge its commodity price risk, both to protect margins and to ensure supply during periods of high demand. Derivative instruments are used to hedge a portion of the Partnership’s forecasted purchases for no more than one year in the future. At September 29, 2007, the fair value of derivative instruments described above resulted in derivative assets (unrealized gains) of $2,544 included within prepaid expenses and other current assets and derivative liabilities (unrealized losses) of $458 included within other current liabilities. As of September 29, 2007, unrealized gains on derivative instruments designated as cash flow hedges in the amount of $1,377 were included in OCI and are expected to be recognized in earnings during the next 12 months as the hedged forecasted transactions occur. However, due to the volatility of the commodities market, the corresponding value in OCI is subject to change prior to its impact on earnings.
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Table of ContentsGains and losses attributable to the mark-to-market adjustments on derivative instruments not designated as hedges under SFAS 133 for all periods presented are reported within cost of products sold. For the years ended September 29, 2007, September 30, 2006 and September 24, 2005, cost of products sold included gains (losses) in the amount of ($7,555), $14,472 and ($2,497), respectively, attributable to changes in the fair value of derivative instruments not designated as cash flow hedges.
As of September 29, 2007, an unrealized loss of $284 was included in OCI attributable to the Partnership’s interest rate swap agreement and is expected to be recognized in earnings as the interest on the Term Loan impacts earnings through March 31, 2010. However, due to changes in the interest rate environment, the corresponding value in OCI is subject to change prior to its impact on earnings.
Credit Risk. The Partnership’s principal customers are residential 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 2007, 2006 or 2005 and no concentration of receivables exists as of September 29, 2007 or September 30, 2006.
Futures 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.
Fair Value of Financial Instruments. The fair value of cash and cash equivalents is not materially different from their carrying amounts because of the short-term nature of these instruments. The fair value of the Revolving Credit Agreement approximates the carrying value since the interest rates are periodically adjusted to reflect market conditions. Based on the current rates offered to the Partnership for debt of the same remaining maturities, the carrying value of the Partnership’s 2003 Senior Notes approximates their fair market value.
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 $19,611, $27,217 and $28,559 for the years ended September 29, 2007, September 30, 2006 and September 24, 2005, respectively.
Future minimum rental commitments under noncancelable operating lease agreements as of September 29, 2007 are as follows:
Contingencies.
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 29, 2007 and September 30, 2006, the Partnership had accrued liabilities of $50,308 and $45,413, 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
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Table of Contentsresults of operations, after considering its self-insurance liability for known and unasserted self-insurance claims. For the portion of the estimated self-insurance liability that exceeds insurance deductibles, the Partnership records an asset within other assets related to the amount of the liability expected to be covered by insurance which amounted to $13,858 and $8,665 as of September 29, 2007 and September 30, 2006, respectively.
On October 23, 2007 the Partnership settled an ongoing litigation case regarding its general and product liability for $4,750. As a result of the settlement, the Partnership reduced the portion of its estimated self-insurance liability that exceeded the insurance deductible and corresponding asset by $400 as of September 29, 2007.
Environmental. The Partnership is 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. 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. However, the Partnership owns real property where such hazardous substances may exist.
The Partnership is also subject to various laws and governmental regulations concerning environmental matters and expects that it will be required to expend funds to participate in the remediation of certain sites, including sites where it has been designated by the Environmental Protection Agency as a potentially responsible party under CERCLA and at sites with aboveground and underground fuel storage tanks.
With the Agway Acquisition, the Partnership acquired certain surplus properties with either known or probable environmental exposure, some of which are currently in varying stages of investigation, remediation or monitoring. Additionally, the Partnership identified that certain active sites acquired contained environmental conditions which may require further investigation, future remediation or ongoing monitoring activities. The environmental exposures include instances of soil and/or groundwater contamination associated with the handling and storage of fuel oil, gasoline and diesel fuel.
Estimating the extent of the Partnership’s 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 the Partnership, at that site. However, management believes that the Partnership’s past experience provides a reasonable basis for estimating these liabilities. As additional information becomes available, estimates are adjusted as necessary. While management does not anticipate that any such adjustment would be material to the Partnership’s financial statements, the result of ongoing or future environmental studies or other factors could alter this expectation and require recording additional liabilities. Management currently cannot determine whether the Partnership will incur additional liabilities or the extent or amount of any such liabilities. As of September 29, 2007 and September 30, 2006, the environmental reserve amounted to $2,578 and $4,786, respectively, and the corresponding asset for expected reimbursements amounted to $50 and $1,294, respectively.
Future developments, such as stricter environmental, health or safety laws and regulations thereunder, could affect the Partnership’s operations. Management does not anticipate that the cost of the Partnership’s 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 the Partnership’s financial condition or results of operations. To the extent there are any environmental liabilities presently unknown to the Partnership or environmental, health or safety laws
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Table of Contentsor regulations are made more stringent, however, there can be no assurance that the Partnership’s financial condition or results of operations will not be materially and adversely affected.
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, 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.
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 2014. 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 $15,330. The fair value of residual value guarantees for outstanding operating leases was $-0- as of September 29, 2007 and September 30, 2006.
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, 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. The $1,284 in net cash proceeds resulted in a gain of $885. Accordingly, the Partnership recorded gains on sale of $1,887 which was accounted for within discontinued operations in accordance with SFAS No. 144, ‘‘Accounting for the Impairment or Disposal of Long-Lived Assets’’ (‘‘SFAS 144’’). Current and prior period results of operations attributable to these customer service centers were not significant and, as such, have not been reclassified to remove its financial results from continuing 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 $54,000 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 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 approximately $40,000 will be 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 have been reported within discontinued operations on the consolidated statements of
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Table of Contentsoperations for fiscal years 2007, 2006 and 2005, and the assets and liabilities have been classified as held for sale on the consolidated balance sheet as of September 29, 2007. Because the transaction closed subsequent to the end of fiscal 2007, the Partnership’s cash on hand at September 29, 2007 does not include the $54,000 of approximate net proceeds from the sale.
During fiscal 2005, the Partnership finalized certain purchase price adjustments with the buyer of customer service centers sold in fiscal 2004 and recorded an additional gain on sale of $976.
The Partnership manages and evaluates its operations in six segments, four of which are reportable segments: Propane, Fuel Oil and Refined Fuels, Natural Gas and Electricity and HVAC. 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.
The HVAC segment is engaged in the sale, installation and servicing of a wide variety of home comfort equipment and parts, particularly in the areas of heating, ventilation and air conditioning. In furtherance of the Partnership’s efforts to restructure its field operations and to focus on its core operating segments, during fiscal 2006 the Partnership initiated plans to streamline the HVAC service offerings by significantly reducing installation activities and focusing on service offerings that support the Partnership’s existing customer base within its propane, refined fuels and natural gas and electricity segments.
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Table of ContentsThe 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:
2007
2006
2005 Revenues:
2007
2006F-31
Table of ContentsFor the year ended September 30, 2006, income (loss) before interest expense, loss on debt extinguishment and provision for income taxes for the propane, fuel oil and refined fuels, HVAC and all other segments included restructuring charges of $2,802, $500, $1,854 and $920, respectively. In addition, depreciation and amortization expense for the propane and all other segments for the year ended September 30, 2006 reflected non-cash charges of $187 and $907, respectively, for the impairment of fixed assets (see Note 4).
For the year ended September 24, 2005, income (loss) before interest expense, loss on debt extinguishment and provision for income taxes for the propane, fuel oil and refined fuels and HVAC segments included $2,525, $125 and $125, respectively, for restructuring charges (see Note 6); and for the HVAC segment included the non-cash charge of $656 for goodwill impairment (see Note 5). In addition, depreciation and amortization expense for the HVAC segment for the year ended September 24, 2005 reflected the non-cash charge of $810 for the impairment of other intangible assets (see Note 5).
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INDEX TO FINANCIAL STATEMENT SCHEDULE
SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES
September 30, 2006 and September 24, 2005S-1
SCHEDULE II
SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
(in thousands)
Beginning
of Period
to Costs and
Expenses
Additions
at End
of Period Year Ended September 24, 2005S-2
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