================================================================================ ================================================================================
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
27, 200324, 2005[ ] 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
(Exact name of registrant as specified in its charter)Delaware 22-3410353 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.)
Delaware 22-3410353 (State or other jurisdiction of
incorporation or organization)(I.R.S. Employer
Identification No.)240 Route 10 West
Whippany, NJ 07981
(973) 887-5300(Address,
(Address, including zip code, and telephone number,
including area code, ofregistrant'sregistrant’s principal executive offices)Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered Common Units New York Stock Exchange
Title of each class Name of each exchange on which registered Common Units New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes [X] No [ ]
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the 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'sregistrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this form 10-K.[X][ ]Indicate by check mark whether registrant is an accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes [X] No [ ]
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
November 21, 2003March 25, 2005 of theregistrant'sregistrant’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 ($31.1734.31 per unit), was approximately$847,035,000. As of November 21, 2003 there were 27,266,767 Common Units outstanding.$1,038,846,000.Documents Incorporated by Reference:
None ================================================================================ ================================================================================Portions of Part III from the Proxy Statement to be filed in connection with the registrant’s 2006 tri-annual meeting.
SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES
INDEX TO ANNUAL REPORT ON FORM 10-K
PART I Page ---- ITEM 1. BUSINESS......................................................... 1 ITEM 2. PROPERTIES....................................................... 7 ITEM 3. LEGAL PROCEEDINGS................................................ 8 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.............. 8 PART II ITEM 5. MARKET FOR THE REGISTRANT'S UNITS AND RELATED UNITHOLDER MATTERS............................................... 9 ITEM 6. SELECTED FINANCIAL DATA..........................................10 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS....................13 ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK......................................................26 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA......................28 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE..............................31 ITEM 9A.CONTROLS AND PROCEDURES..........................................31 PART III ITEM 10.DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT...............32 ITEM 11.EXECUTIVE COMPENSATION...........................................35 ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT...................................................40 ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS...................41 ITEM 14.PRINCIPAL ACCOUNTING FEES AND SERVICES...........................41 PART IV ITEM 15.EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K..............................................42 Signatures...................................................................43
Page PART I ITEM 1. BUSINESS 1 ITEM 2. PROPERTIES 9 ITEM 3. LEGAL PROCEEDINGS 10 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 10 PART II ITEM 5. MARKET FOR THE REGISTRANT’S UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF UNITS 11 ITEM 6. SELECTED FINANCIAL DATA 12 ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 15 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 35 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 37 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 40 ITEM 9A. CONTROLS AND PROCEDURES 40 ITEM 9B. OTHER INFORMATION 41 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT 42 ITEM 11. EXECUTIVE COMPENSATION 42 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT 42 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 42 ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES 42 PART IV ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES 43 SIGNATURES 44 DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS
- -----------------------------------------------This Annual Report on Form 10-K contains forward-looking statements
("(‘‘Forward-LookingStatements"Statements’’) as defined in the Private Securities Litigation Reform Act of 1995 and Section 27A of the Securities Act of 1933, as amended, relating tothe Partnership'sfuture business expectations and predictions and financial condition and results ofoperations.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"‘‘prospects,’’ ‘‘outlook,’’ ‘‘believes,’’ ‘‘estimates,’’ ‘‘intends,’’ ‘‘may,’’ ‘‘will,’’ ‘‘should,’’ ‘‘anticipates,’’ ‘‘expects’’ or"plans"‘‘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 ‘‘CautionaryStatements"Statements’’). The risks and uncertainties and their impact on thePartnership's operationsPartnership’s results include, but are not limited to, the following risks:
• The impact of weather conditions on the demand for propane, fuel oil and other refined fuels, natural gas and electricity;
• Fluctuations in the unit cost of propane, fuel oil and other refined fuels and natural gas, and the impact of price increases on customer conservation; o The impact of weather conditions on the demand for propane; o Fluctuations in the unit cost of propane; o The ability of the Partnership to compete with other suppliers of propane and other energy sources; o The impact on propane prices and supply from the political and economic instability of the oil producing nations and other general economic conditions; o The ability of the Partnership to retain customers; o The impact of energy efficiency and technology advances on the demand for propane; o The ability of management to continue to control expenses; o The impact of regulatory developments on the Partnership's business; o The impact of legal proceedings on the Partnership's business; o The Partnership's ability to implement its expansion strategy into new business lines and sectors; o The Partnership's ability to integrate acquired businesses successfully.
• The ability of the Partnership to compete with other suppliers of propane, fuel oil and other energy sources;
• The impact on the price and supply of propane, fuel oil and other refined fuels from the political, military or economic instability of the oil producing nations, global terrorism and other general economic conditions;
• The ability of the Partnership to continue to realize, or to realize fully, within the expected timeframe, the expected cost savings and synergies from the Agway Acquisition (as defined below);
• The ability of the Partnership to acquire and maintain reliable transportation for its propane, fuel oil and other refined fuels;
• The ability of the Partnership to retain customers;
• The impact of energy efficiency and technology advances on the demand for propane and fuel oil;
• The ability of management to continue to control expenses, including the results of our recent field realignment initiative;
• The impact of changes in applicable statutes and government regulations, or their interpretations, including those relating to the environment and global warming and other regulatory developments on the Partnership’s business;
• The impact of legal proceedings on the Partnership’s business;
• The Partnership’s ability to implement its expansion strategy into new business lines and sectors; and
• The Partnership’s ability to integrate acquired businesses successfully. Some of these Forward-Looking Statements are discussed in more detail in
"Management's‘‘Management’s Discussion and Analysis of Financial Condition and Results ofOperations"Operations’’ in this Annual Report. On different occasions, the Partnership or its representatives have made or may make Forward-Looking Statements in other filingsthat the Partnership makeswith the Securities and Exchange Commissionin(‘‘SEC’’), press releases orinoral statements made by or with the approval of one ofitsthe Partnership’s authorized executive officers. Readers are cautioned not to place undue reliance on Forward-Lookingor CautionaryStatements, which reflectmanagement's opinionsmanagement’s view only as of the datehereof.made. The Partnership undertakes no obligation to update any Forward-Looking Statement or Cautionary Statement. 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.PART I
ITEM 1. BUSINESS
GENERALDevelopment of Business
Suburban Propane Partners, L.P. (the
"Partnership"‘‘Partnership’’), a publicly traded Delaware limited partnership, isprincipally engaged, through its operating partnershipa nationwide marketer andsubsidiaries,distributor of a diverse array of products to meet the energy needs of our customers. We specialize in propane, fuel oil and other refined fuels, as well as the marketing of natural gas and electricity in deregulated markets. To complement our core marketing and distribution operations, we install and service a variety of home comfort equipment, particularly in theretailareas of heating, ventilation andwholesale marketing of propane and related appliances, parts and services. Basedair conditioning (‘‘HVAC’’). We believe, based on LP/Gas Magazine dated February2003, we believe2005, that we are the third largest retail marketer of propane in the United States, measured by retail gallons sold in the year 2004. As of September 24, 2005, we were servingapproximately 750,000the energy needs of more than 1,000,000 active residential, commercial, industrial and agricultural customers through approximately320370 customer service centers in4030 statesas of September 27, 2003. Our operations are concentratedlocated primarily in the east and west coast regions of the United States.OurWe sold approximately 516.0 million gallons of propane to retailpropane sales volume was approximately 491.5customers and 244.5 million gallons of fuel oil and other refined fuels during the year ended September27, 2003. In addition,24, 2005. Together with our predecessor companies, wesold approximately 31.7 million gallons ofhave been continuously engaged in the retail propaneat wholesale to large industrial end-users and other propane distributors during the fiscal year. Based on industry statistics contained in 2001 Sales of Natural Gas Liquids and Liquefied Refinery Gases, as published by the American Petroleum Institute in November 2002, our sales volume accounted for approximately 4.4% of the domestic retail market for propane during the year 2001.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"‘‘Operating Partnership’’)., and its direct and indirect subsidiaries. Our general partner is Suburban Energy Services Group LLC (the"General Partner"‘‘General Partner’’), a Delaware limited liability companyownedmajority-owned by members of our senior management. The General Partner owns a combined1.71%1.54% general partner interest in the Partnership and the Operating Partnership and the Partnership owns all of the limited partnership interests in the Operating Partnership.The Partnership andSubsidiaries of the Operating Partnership
commenced operations on March 5, 1996 upon consummation of an initial public offering of common units representing limited partner interests in the Partnership ("Common Units") and the private placement of $425 million aggregate principal amount of Senior Notes.include Suburban Sales and Service, Inc. (the"Service Company"‘‘Service Company’’), which conducts a portion of the Partnership’s service work and appliance and parts businesses. Additionally, on January 5, 2001, Suburban Holdings, Inc., a subsidiary of the Operating Partnership, was formedat that timetooperatehold theservice work and appliance and propane equipment parts businessesstock ofthe Partnership. Other subsidiaries of the Operating Partnership includeGas Connection, Inc.(doing business as(d/b/a HomeTown Hearth & Grill), Suburban @ Home,("Suburban @ Home"),Inc. and Suburban Franchising, Inc.("Suburban Franchising").HomeTown Hearth & Grill sells and installs natural gas and propane gas grills, fireplaces and related accessories and supplies throughtwelvethirteen retail stores in the south, northeast and northwest regions as of September27, 2003;24, 2005. Suburban @ Home sells, installs, services and repairs a full range ofheating and air conditioning products through five retail locations in the south, northeast and northwest regions as of September 27, 2003; andHVAC products. 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’’). Agway Energy was a leading regional marketer of propane, fuel oil, gasoline and diesel fuel primarily in New York, Pennsylvania, New Jersey and Vermont, as well as a marketer of natural gas and electricity in New York and Pennsylvania. 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 other refined fuels, as well as the marketing of natural gas and electricity. The total cost of the Agway Acquisition, including the purchase price of $205.0 million (net of a working capital adjustment paid to the Partnership of $1.0 million), $2.7 million for non-compete agreements with certain members of the management of Agway Energy and $3.5 million in transaction related costs, was approximately $211.2 million.
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 other 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, a portion of which was used to finance the Agway Acquisition. Suburban Energy Finance Corporation has nominal assets and conducts no business operations.
In this Annual Report, unless otherwise indicated, the terms
"Partnership," "we," "us,"‘‘Partnership,’’ ‘‘we,’’ ‘‘us,’’ and"our"‘‘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"(‘‘SEC’’).The publicYou may read and copy any materials that we file with the SEC at theSEC'sSEC’s Public Reference Room at 450 Fifth Street, N. W., Washington, D.C. 20549.The publicYou 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 theSEC'sSEC’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 fiscal year ended September
27, 2003,24, 2005, 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 the1SEC. Requests should be directed to: Suburban Propane Partners, L.P., Investor Relations, P.O. Box 206, Whippany, New Jersey 07981-0206. RECENT DEVELOPMENTS On November 10, 2003, we entered into an asset purchase agreement (the "Purchase Agreement") to acquire substantially all of the assets and operations of Agway Energy Products, LLC, Agway Energy Services PA, Inc. and Agway Energy Services, Inc. (collectively "Agway Energy"), all of which entities are wholly owned subsidiaries of Agway, Inc., for $206.0 million in cash, subject to certain purchase price adjustments. Agway Energy, based in Syracuse, New York, is a leading regional marketer of propane, fuel oil, gasoline and diesel fuel primarily in New York, Pennsylvania, New Jersey and Vermont. Based on LP/Gas Magazine dated February 2003, Agway Energy is the eighth largest retail propane marketer in the United States, operating through approximately 139 distribution and sales centers. Agway Energy is also one of the leading marketers and distributors of fuel oil in the northeast region of the United States. To complement its core marketing and delivery business, Agway Energy installs and services a wide variety of home comfort equipment, particularly in the area of heating, ventilation and air conditioning ("HVAC"). Additionally, to a lesser extent, Agway Energy markets natural gas and electricity in New York and Pennsylvania. For its fiscal year ended June 30, 2003, Agway Energy served more than 400,000 active customers across all of its lines of business and sold approximately 106.3 million gallons of propane and approximately 356.8 million gallons of fuel oil, gasoline and diesel fuel to retail customers for residential, commercial and agricultural applications. See additional discussion in Note 15 to the Consolidated Financial Statements included in this Annual Report. Agway Energy is comprised of three wholly-owned subsidiaries of Agway, Inc. Agway, Inc. is presently a debtor-in-possession under Chapter 11 of the Bankruptcy Code in a bankruptcy proceeding pending before the United States Bankruptcy Court for the Northern District of New York (the "Bankruptcy Court"). Agway Energy is not a Chapter 11 debtor. The Purchase Agreement was filed with the Bankruptcy Court and on November 24, 2003, the Bankruptcy Court approved Agway, Inc.'s motion to establish bid procedures for the sale. Under the Bankruptcy Court order, we were officially designated the "stalking horse" bidder in a process in which additional bids for the Agway Energy assets and business operations are being solicited for a specified period of time. An auction is currently scheduled for December 18, 2003. If we are the successful bidder at the auction, the closing on the sale under the Purchase Agreement is expected to occur shortly following the conclusion of the auction process and upon receipt of necessary regulatory approvals. There can be no assurance that we will ultimately be the successful bidder at the auction or will be able to consummate the acquisition of Agway Energy. In line with our business strategy, this acquisition, once consummated, will expand our presence in the northeast retail propane market. Additionally, Agway Energy's extensive presence in the northeast fuel oil delivery business expands our product offerings in the attractive northeast energy market and provides an opportunity to leverage our existing management expertise and technology to enhance operational efficiencies within the Agway Energy business. The HVAC business of Agway Energy is more mature than our Suburban @ Home operations and is expected to provide an opportunity to accelerate the growth in this business, as well as to enhance the overall service offering to our existing customer base in the northeast. BUSINESS STRATEGYOur 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 Growth, Customer Service and Improving Operating Efficiency.We
pursue this business strategy through a combination of (i) an internalfocuson enhancing customer service, growing and retaining our customer base and improving the efficiency of operations and, (ii) acquisitions of businesses to complement or supplement our core propane operations. 2Over the past several years, we have focusedinternally on improving the efficiency of our existing operations,andmanaging our cost structure,strengtheningexpanding ourbalance sheetcustomer base anddistribution coverage and building a platform for growth. We continue to pursue internal growth of our existing propane operations and to foster the growth of related retail and service operations that can benefit from our infrastructure and national presence. We investincreasing customer retention through enhanced customer service. Through investments inenhancements toour technology infrastructure, we continue toincreaseseek to improve operating efficiencies, particularly in the areas of routing, forecasting customer usage, inventory control and customer tracking. During fiscal 2005, we took additional steps todevelop marketing programsmore fully integrate our operations in the northeast to achieve the synergies anticipated from the Agway Acquisition. Additionally, during the fourth quarter of fiscal 2005 we initiated plans to consolidate andincentive compensation arrangements focusedrealign our field operations and management, including consolidating regions from nineteen to ten and streamlining our operating footprint within the ten regions. These initiatives are expected to generate further efficiencies and cost saving opportunities at the field operating level.Additionally, 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
retention.success of our operations. ‘‘Our Business is Customer Satisfaction’’ is one of our core operating philosophies. We measure and rewardthe success ofour customer service centers based on a combination of profitability of the individualcustomercustomers service center, net customer growth andsatisfaction statistics andasset utilization measures.Additionally,Selective Acquisitions of Complementary Businesses or Assets. Externally, we
continuously evaluate our existing facilities to identify opportunities to optimize our return on assets by selectively divesting operations in slower growing markets andseek toreinvest in markets that present more opportunities for growth. In addition toextend ourinternal growth strategies, we have evaluated several acquisition opportunities both within the propane sector, as well as in other energy-related businesses in an effort to acceleratepresence or diversify ouroverall growth strategy.product offerings through selective acquisitions. Our acquisition strategy is to focus on businesses with a relatively steady cash flow that will either extend our presence in strategically attractivepropanemarkets, complement our existingnetwork of propane operationsbusiness segments or provide an opportunity to diversify our operations with other energy-related assets.InWhile we are active in thisregard, as further discussed above,area, webelieve thatare also very patient and deliberate in evaluating acquisition candidates. During thepending acquisitionfirst quarter of fiscal 2004, we completed theassets ofAgwayEnergy wouldAcquisition, which significantlyenhanceenhanced our position in the northeast propane market andexpanddiversified our productand serviceofferings tofurther supportinclude the marketing and distribution of fuel oil and other refined fuels, as well as the marketing of natural gas and electricity. In addition, the Agway Acquisition brought us many skilled and experienced service personnel for ouroverallHVAC segment.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
objectives. INDUSTRY BACKGROUND AND COMPETITIONand profit potential of all of our assets.Business Segments
Our principal operations are managed and evaluated in five business segments: Propane, Fuel Oil and Other Refined Fuels, Natural Gas & Electricity, HVAC and All Other. These business segments are described below. See Note 18 to the Consolidated Financial Statements included in this Annual Report for financial information about our business segments.
Propane
Propane is a by-product of natural gas processing and petroleum refining. It is a
clean-burningclean burning energy source recognized for its transportability and ease of use relative to alternative forms of stand-alone energy sources.Retail propanePropane use falls into three broad categories:(i) residential and commercial applications, (ii) industrial applications and (iii) agricultural uses.
• residential and commercial applications;
• industrial applications; and
• agricultural uses. In the residential and commercial markets, propane is used primarily for space heating, water heating, clothes drying and cooking. Industrial customers use propane generally as a motor fuel
burned in internal combustion engines thatto 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.
PropaneIt 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,itpropane becomes a flammable gas that is colorless and odorless,withalthough an odorant is added to allowforits detection. Propane is clean burning and, when consumed, produces only negligible amounts of pollutants.Based upon informationProduct Distribution and Marketing
We distribute propane through a nationwide retail distribution network consisting of approximately 370 customer service centers in 30 states as of September 24, 2005. Our operations are concentrated in the east and west coast regions of the United States. In fiscal 2005, we serviced approximately 830,000 active propane customers. Typically, 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. From our customer service centers, we also sell, install and service equipment related to our propane distribution business, 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 92% of the propane gallons sold by us in fiscal 2005 were to retail customers: 44% to residential customers, 31% to commercial customers, 9% to industrial customers, 6% to agricultural customers and 10% to other retail users. The balance of approximately 8% of the propane gallons sold by us in fiscal 2005 was for risk management activities and wholesale customers. Sales to residential customers in fiscal 2005 accounted for approximately 61% of our margins on retail propane sales, reflecting the higher-margin nature of the residential market. No single customer accounted for 10% or more of our propane revenues during fiscal 2005.
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 customer’s premises. The capacity of these storage tanks ranges from approximately 100 gallons to approximately 1,200 gallons, with a typical tank having a capacity of 300 to 400 gallons. As is common in the propane industry, we own a significant portion of the storage tanks located on our customer’s 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 71 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 facilities in Elk Grove, California and Tirzah, South Carolina) 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 2006. During fiscal 2005, Dynegy Liquids Marketing and Trade (‘‘Dynegy’’) and Enterprise Products Operating L.P. (‘‘Enterprise’’) provided approximately 17% 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 2005. 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 Dynegy 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 98% of our total propane purchases were from domestic suppliers in fiscal 2005.
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 Item 7A of this Annual Report.
We own and operate large propane storage facilities in California and South Carolina. We also operate smaller storage facilities in other locations and have rights to use storage facilities in additional locations. These storage facilities enable us to buy and store large quantities of propane during periods of low demand and lower prices, which generally occur during the
National Propane Gas Associationsummer months. This practice helpsensure a more secure supply of propane during periods of intense demand or price instability. As of September 24, 2005, the majority of our storage capacity in California and South Carolina was leased to third parties.
Competition
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
electricity,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,
affected,we believe new opportunities for propane sales have been arising as new neighborhoods are developed in geographically remote areas.PropaneWe 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
compete to a lesser extentare not significant competitors because of the cost of converting3from one to the other. In addition to competing with suppliers of other energy sources,
or energy, weour propane operations compete with other retail propane distributors.Competition in theThe 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 in20012003 Sales of Natural Gas Liquids andLiquifiedLiquefied Refinery Gases, as published by the American Petroleum Institute inNovember 2002,February 2005, and LP/Gas Magazine dated February2003,2005, the ten largest retailers, including us, account for approximately29%33% 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 UnitedStates and our sales volume accounted for approximately 4.4% of the domestic retail market for propane during 2001.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.PRODUCTS, SERVICES AND MARKETINGFuel Oil and Other Refined Fuels
We market and distribute
propane through a nationwide retail distribution network consisting offuel oil, diesel fuel, kerosene and gasoline to approximately320 customer service centers in 40 states as of September 27, 2003. Our operations are concentrated180,000 residential and commercial customers in theeast and west coast regionsnortheast region. We commenced operations in this business segment as a result of theUnited States. InAgway Acquisition and, accordingly, our results for fiscal2003, we serviced approximately 750,000 active customers.2004 include this segment from the date of the Agway Acquisition (December 23, 2003). Sales of fuel oil and other refined fuels for fiscal 2005 amounted to 244.5 million gallons. During fiscal 2005, sales of fuel oil to residential customers, principally for home heating, represented 40% of total refined fuel gallons sold. Fuel oil has a more limited use, compared to propane, for space and water heating in residential and commercial buildings.Approximately
two-thirds74% of ourretail propane volume has historically been sold during the six month peak heating season from October through March, as many customers use propane for heating purposes. Typically, customer service centers are found in suburban and rural areas where natural gas is not readily available. Generally, such locations 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 residentialfuel oil customers receive theirpropane supply pursuant tofuel oil under an automatic delivery systemthat eliminateswithout thecustomer's needcustomer having to make an affirmative purchase decision.FromThese 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 ourcustomer service centers, we also sell, installcustomers a budget payment plan whereby the customer’s estimated annual fuel oil purchases and serviceequipment relatedcontracts are paid for in a series of estimated equal monthly payments over a twelve-month period. During fiscal 2005, approximately 70% of our fuel oil sales were made to individual customers under a fuel oil ceilingprogram (the ‘‘Ceiling Program’’) which pre-established a maximum price per gallon over a twelve-month period. While our
propane distribution business, including heatingstrategy was to enter into derivative instruments in the form of futures andcooking 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 94%options traded on the NYMEX covering a majority of the fuel oil we expected to sell to customers under the fuel oil Ceiling Program in an effort to protect the margins under the program, we evaluated the costs of such hedge protection and elected not to hedge February through April deliveries under this program. After evaluating the costs to adequately hedge the fuel oil Ceiling Program in the current commodity price environment, we decided to discontinue offering the fuel oil Ceiling Program after the fiscal 2005 heating season.Deliveries of fuel oil are usually made to customers by means of tankwagon trucks, which have capacities ranging from 2,500 gallons
soldto 3,000 gallons of fuel oil. Fuel oil is pumped from the tankwagon truck into a stationary storage tank that is located on the customer’s premises, which is owned byus in fiscal 2003 werethe customer. The capacity of customer storage tanks ranges from approximately 275 gallons toretail customers: 41% to residential customers, 30% to commercial customers, 10% to industrial customers, 6% to agricultural customers and 13% to other retail users. The balance ofapproximately6% of the gallons sold by us in fiscal 2003 was for risk management activities and wholesale customers. Sales to residential customers in fiscal 2003 accounted for approximately 59% of our margins on propane sales, reflecting the higher-margin nature of the residential market.1,000 gallons. No single customer accounted for 10% or more of our fuel oil revenues during fiscal2003. Retail deliveries of propane are usually made to customers by means of bobtail and rack trucks. Propane is pumped from the bobtail truck, with capacities ranging from 2,125 gallons to 2,975 gallons of propane, into a stationary storage tank on the customer's 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.2005.Supply
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 of propane 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 supplementalobtain fuelto meet peak load deliverability requirements, and large agricultural accounts that use propane for crop drying. Propane is generally transported from refineries, pipeline terminals, storage facilities (including our storage facilities in Elk Grove, California and Tirzah, South Carolina), and coastal terminals to our customer service centers by a combination of common carriers, owner-operators and railroad tank cars. See additional discussion in Item 2 of this Annual Report. 4In our wholesale operations, we principally sell propane to large industrial end-usersoil and otherpropane distributors. Therefined 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 14 terminal facilities we do not own. We have arrangements with certain suppliers of fuel oil, which provide open access to fuel oil at specific terminals throughout the northeast. Additionally, a portion of our purchases of fuel oil are made at local wholesalemarket includes customers who use propane to fire furnaces, as a cutting gas andterminal racks. In most cases, the supply contracts do not establish the price of fuel oil inother process applications. Due to the low margin nature of the wholesaleadvance; rather, prices are typically established based upon marketas compared to the retail market, we have selectively reduced our emphasis on wholesale marketing over the last few years. Accordingly, sales of wholesale gallons during fiscal 2003 decreased in comparison to fiscal 2002, which also decreased from fiscal 2001. PROPANE SUPPLY Our propane supply is purchased from nearly 70 oil companies and natural gas processors at approximately 180 supply points located in the United States and Canada. We make purchases primarily under one-year agreements that are subject to annual renewal, but also purchase propane on the spot market. Supply contracts generally provide for pricing in accordance with postedprices at the time of delivery plus or minus a differential to market for transportation and volume discounts. We purchase fuel oil from nearly 33 suppliers at approximately 75 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 thecurrentavailability of supplies of fuel oil in the future, we currently expect to be able to secure adequate supplies during fiscal 2006.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 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 & 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.
As of September 24, 2005, we were serving nearly 77,000 natural gas and electricity customers in New York and Pennsylvania. During fiscal 2005, we sold approximately 5.9 million dekatherms of natural gas and 558.3 million kilowatt hours of electricity through the natural gas and electricity segment. Approximately 88% of our customers were residential households and the remainder were small commercial and industrial customers. New accounts are obtained through numerous marketing and advertising programs, including telemarketing and direct mail initiatives. Most local utility companies have established billing service arrangements whereby customers receive a single bill from the local utility company which includes transmission 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
major storage points,the time of delivery, and some contracts include a pricing formula that typically is based on prevailing market prices.SomeThe majority ofthese agreements provide maximum and minimum seasonal purchase guidelines. We use a number of interstate pipelines,our electricity requirements are purchased through the New York Independent System Operator (‘‘NYISO’’) under an annual supply agreement, as well asrailroad tank carspurchase 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 anddelivery trucks to transport propane from suppliers to storageelectricity providing similar alternatives as AES.HVAC
We sell, install and service all types of whole-house heating and cooling products, air cleaners, humidifiers, de-humidifiers, hearth products and space heaters. We also offer services such as duct cleaning, air balancing and energy audits. Our supply needs are filled through supply arrangements with several large regional equipment manufacturers and distribution
facilities. Historically, suppliescompanies. 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.All Other
The All other business segment is comprised of
propanethe activities from oursupply sources have been readily available. Although we make no assurance regardingHomeTown Hearth & Grill and Suburban Franchising subsidiaries.Seasonality
The retail propane and fuel oil distribution businesses, as well as the
availabilitynatural gas marketing business, are seasonal because ofsuppliesthe primary use ofpropanethese fuels for heating inthe future, we currently expect to be able to secure adequate supplies during fiscal 2004. During fiscal 2003, Dynegy Liquids Marketingresidential andTrade ("Dynegy") and Enterprise Products Operating L.P. ("Enterprise") providedcommercial buildings. Historically, approximately21% and 13%, respectively,two-thirds of ourtotal domesticretail propanesupply.volume is sold during the six-month peak heating season from October through March. Theavailabilityfuel 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,
supplyfuel oil and natural gas, for both heating and agricultural purposes. Many of our customers rely heavily on propane, fuel oil or natural gas as a heating source. Accordingly, the volume sold isdependent on several factors, includingdirectly 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 andthe price and availability of competing fuels such asnatural gas consumption, while sustained colder than normal temperatures will tend to result in greater use.Trademarks and
heating oil. We believe that, if supplies from Dynegy 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. Aside from these two suppliers, no single supplier provided more than 10% of our total domestic propane supply fiscal 2003. During that year, approximately 98% of our total propane purchases were from domestic suppliers. 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 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 commodity trading policy. See additional discussion in Item 7A of this Annual Report. We operate large propane storage facilities in California and South Carolina. We also operate smaller storage facilities in other locations and have rights to use storage facilities in additional locations. As of September 27, 2003, the majority of the storage capacity in California and South Carolina was leased to third parties. Our storage facilities enable us to buy and store large quantities of propane during periods of low demand and lower prices, 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. TRADEMARKS AND TRADENAMESTradenamesWe utilize a variety of trademarks and tradenames owned by us, including
"Suburban‘‘Suburban Propane," "Gas’’ ‘‘Gas Connection,"’’ ‘‘HomeTown Hearth & Grill,’’ ‘‘Suburban @ Home’’ and"Suburban @ Home."‘‘Suburban Energy Services.’’ 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 ourproducts. 5GOVERNMENT REGULATION; ENVIRONMENTAL AND SAFETY MATTERSproducts 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"(‘‘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"‘‘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"‘‘hazardous substance’’ into the environment. Propane is not a hazardous substance within the meaning of CERCLA. However, we own real property at locations where such hazardous substances mayexistbe 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 (‘‘EPA’’) as a potentially responsible party (‘‘PRP’’) under CERCLA and at sites with above ground 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 properties and assets, including fuel oil tanks and gasoline stations, that are subject to extensive federal, state and local environmental laws and regulations, including investigation and remediation of contaminated soil and groundwater, transportation of hazardous materials, other environmental protection measures and health and safety matters. Based on a review of certain Phase I Environmental Site Assessments and, at certain sites, groundwater and/or soil sample analysis, we identified that certain of these properties had either known or probable environmental exposure, some of which are currently in varying stages of investigation, remediation or monitoring. Under the agreement for the Agway Acquisition, the seller deposited $15.0 million of the total purchase price into an escrow account to be used to fund our remediation costs at the acquired properties pursuant to claims made during the first three years following the closing date. Subject to amounts withheld with respect to any pending claims made prior to the third anniversary of the closing date of the Agway Acquisition, any remaining escrowed funds will be remitted to the seller at the end of the three-year period.
During fiscal 2004, based on our best estimate of future costs for environmental investigations, remediation and ongoing monitoring activities associated with properties acquired in the Agway Acquisition with either known or probable environmental exposures, an environmental reserve in the amount of $13.8 million was established in purchase accounting. We established a corresponding environmental escrow asset in the amount of $13.8 million related to the future reimbursement from escrowed funds for environmental spending. We are unable to predict, however, whether this amount will be sufficient to address the known and any currently unknown contamination at the acquired properties. As of September 24, 2005, the remaining environmental reserve and corresponding environmental escrow asset amounted to approximately $5.8 million and $6.2 million, respectively. The environmental reserves are recorded on an undiscounted basis.
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. However, we believe that our past experience provides a reasonable basis for estimating these liabilities. As additional information becomes available, estimates are adjusted as necessary. While we do not anticipate that any such adjustment would be material to our financial statements, the result of ongoing or future environmental studies or other factors could alter this expectation and require recording additional liabilities. We currently cannot determine whether we will incur additional liabilities or the extent or amount of any such liabilities.
National Fire Protection Association
Pamphlets No.Pamphlet Nos. 54 andNo.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 becompletecompleted by June 2011.AWe have a programisin place to meet this deadline.National Fire Protection Association Pamphlet Nos. 30, 30A, 31, 385 and 395, which establish rules and procedures governing the
deadline.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
agency.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 Transportation has established regulations addressing emergency discharge control issues. The regulations, which became effective as of July 1, 1999, required us to modify the inspection and record keeping procedures for our cargo tank vehicles. A schedule of compliance is set forth within the regulations. We have implemented the required discharge control systems and comply, in all material respects, with current regulatory requirements.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
that there arewe 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.EMPLOYEESEmployees
As of September
27, 2003,24, 2005, we had approximately2,9734,079 full time employees, of whom285368 were engaged in general and administrative activities (including fleet maintenance), 29 were engaged in transportation and product supply activities and2,6593,682 were customer service center employees. As of September27, 2003, 14524, 2005, 104 of our employees were represented by108 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.6ITEM 2. PROPERTIES
As of September
27, 2003,24, 2005, we owned approximately70%74% 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, above-ground propane storage facility in Elk Grove, California and a 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
27, 2003,24, 2005, we had a fleet ofseven27 transport truck tractors, of which we ownedfive,9, and251252 railroad tank cars,allof which weleased.owned two. In addition, as of September27, 200324, 2005 weused 1,148had 1,233 bobtail and rack trucks, of which we owned approximately27%24%, 241 fuel oil tankwagons, of which we owned approximately 61%, and1,3391,958 other delivery and service vehicles, of which we owned approximately29%32%.Vehicles that areWe lease the vehicles we do notowned by us are leased.own. As of September27, 2003,24, 2005, we also owned approximately771,679842,675 customer propane storage tanks with typical capacities of 100 to 500 gallons,37,370183,820 customer propane storage tanks with typical capacities of over 500 gallons and137,682248,475 portable propane cylinders with typical capacities of five to ten gallons.7ITEM 3. LEGAL PROCEEDINGS
LITIGATIONLitigation
Our operations are subject to all operating hazards and risks normally incidental to handling, storing and delivering combustible liquids such as propane. As a result, we have been, and will continue to be, a defendant in various legal proceedings and litigation arising in the ordinary course of business. We are self-insured for general and product,
workers'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$28.6$46.5 million at September27, 2003)24, 2005), 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 orourcash 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 $10.0 million at September 24, 2005).On
May 23, 2001,October 21, 2004 the jury in the trial of Heritage Propane Partners, L.P.("Heritage") amendedv. SCANA et al. returned acomplaint itunanimous verdict in our favor on all claims pending against us by Heritage Propane Partners, L.P. (‘‘Heritage’’). Following our Operating Partnership’s 1999 acquisition of the propane assets of SCANA Corporation (‘‘SCANA’’), Heritage hadfiled on November 30, 1999brought an action in the South Carolina Court of Common PleasFifth Judicial Circuit,for Richland County against SCANACorporation ("SCANA")for breach of contract andCornerstone Ventures, L.P. ("Cornerstone") to name our Operating Partnership as a defendant (Heritage v. SCANA et al., Civil Action 0l-CP-40-3262). Third party insurancefraud andthe self-insurance reserves referenced above do not apply to this action. The amended complaint alleges, among other things, that SCANA breached a contract for the sale of propane assets and asserts claimsagainst our Operating Partnership forwrongfultortious interference with contract and tortious interference with prospectiveadvantagecontract. After the jury returned a verdict against SCANA, the Court conducted a separate bench trial on our cross-claims against SCANA for indemnification, in which we sought to recover our defense costs. The Court granted judgment on our cross-claims against SCANA andcivil conspiracy for allegedly interfering with Heritage's prospective contract with SCANA. Heritage claimsawarded us a total of approximately $2.6 million. However, on November 17, 2005, the Court granted SCANA’s motion to vacate the judgment in our favor. SCANA claimed that, at the time that the order was entered, the Court lacked jurisdiction over our cross-claims because SCANA had appealed the jury verdict against it, thereby divesting the Court of jurisdiction over matters that could be affected by SCANA’s appeal. SCANA further claimed that if the judgment against it isentitledvacated on appeal, it would have no liability torecover its alleged lost profits inus for our defense costs. We have requested that theamountCourt modify the November 17, 2005 order vacating the award of$125.0 million and that all defendants are jointly and severally liable to it for such amount. Our Operating Partnership moved to dismiss the claims asserted against it for failure to state a claim. On October 24, 2001, the court denied our Operating Partnership's motion to dismiss the amended complaint. On February 6, 2003, the plaintiffs in Heritage v. SCANA et al filed a motion to amend its complaint to assert additional claims against all defendants, including three new claims against our Operating Partnership: aiding and abetting; misappropriation; and unjust enrichment. The court has granted this motion. On May 5, 2003, our Operating Partnership filed a motion for summary judgement to dismiss the claims asserted against it in the original complaint filed against our Operating Partnership. We withdrew this motion for strategic reasons butfees; we intend tore-file it at a later date. However, we cannot predictseek further reconsideration of that order and to seek to have theoutcomeaward ofthis motion for summary judgement. Discovery is ongoing between all parties to the lawsuit. We do not anticipate that this matter will be tried before the Spring of 2004. We believe that the claims and proposed additional claims against our Operating Partnership are without merit and are defending the action vigorously. If this matter proceeds to trial, we cannot predict the outcome of this trial, or , if the trial is before a jury, what verdict the jury ultimately may reach.fees reinstated.ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
8PART II
ITEM 5. MARKET FOR THE REGISTRANT'S
ITEM 5. MARKET FOR THE REGISTRANT’S UNITS, ANDRELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF UNITS(a) Our Common Units, representing limited partner interests in the Partnership, are listed and traded on the New York Stock Exchange
("NYSE"(‘‘NYSE’’) under the symbol SPH. As of November21, 2003,28, 2005, there were982890 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 with respect to each quarter.Common Unit Price Range ------------------------ Cash Distribution High Low Paid ----------- ----------- ----------------- Fiscal 2002 ----------- First Quarter $ 27.99 $ 24.50 $ 0.5625 Second Quarter 28.40 24.36 0.5625 Third Quarter 28.25 25.59 0.5750 Fourth Quarter 28.49 20.00 0.5750 Fiscal 2003 ----------- First Quarter $ 28.49 $ 24.60 $ 0.5750 Second Quarter 29.60 26.90 0.5750 Third Quarter 29.89 27.40 0.5875 Fourth Quarter 30.95 27.91 0.5875
Common Unit Price Range Cash Distribution
Paid per Common UnitHigh Low Fiscal 2004 First Quarter $ 32.49 $ 28.75 $ 0.5875 Second Quarter 34.50 31.05 0.6000 Third Quarter 33.97 27.60 0.6125 Fourth Quarter 35.50 32.00 0.6125 Fiscal 2005 First Quarter $ 35.70 $ 30.00 $ 0.6125 Second Quarter 36.00 33.45 0.6125 Third Quarter 35.70 31.55 0.6125 Fourth Quarter 37.40 25.39 0.6125 We make quarterly distributions to our partners in an aggregate amount equal to our Available Cash (as defined in
theour Second Amended and Restated Partnership Agreement) with respect to such quarter. Available Cash generally means all cash on hand at the end of the fiscal quarter plus all additional cash on hand as a result of borrowings subsequent to the end of such quarter less cash reserves established by the Board of Supervisors in its reasonable discretion for future cash requirements.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.
9
(b) Not applicable.
(c) None. ITEM 6. SELECTED FINANCIAL DATA
The following table presents our selected consolidated historical financial data. The selected consolidated historical financial data is derived from our audited consolidated financial
statements. Thestatements, certain of which are included elsewhere in this Annual Report. All amounts in the table below, except per unit data, are in thousands.
Year Ended September 24,
2005September 25,
2004 (a)September 27,
2003September 28,
2002September 29,
2001Statement of Operations Data Revenues $ 1,620,234 $ 1,307,254 $ 735,075 $ 635,122 $ 890,349 Costs and expenses 1,548,436 1,231,356 655,225 552,341 796,507 Restructuring costs (b) 2,775 2,942 — — — Impairment of goodwill (c) 656 3,177 — — — Gain on sale of storage facility — — — (6,768 ) — Income before interest expense, loss on debt extinguishment and provision for income taxes (d) 68,367 69,779 79,850 89,549 93,842 Loss on debt extinguishment (e) 36,242 — — — — Interest expense, net 40,374 40,832 33,629 35,325 39,596 Provision for income taxes 803 3 202 703 375 (Loss) income from continuing operations (d) (9,052 ) 28,944 46,019 53,521 53,871 Discontinued operations: Gain on sale of customer service centers (f) 976 26,332 2,483 — — (Loss) income from discontinued customer service centers — (972 ) 167 3 (361 ) Net (loss) income (d) (8,076 ) 54,304 48,669 53,524 53,510 (Loss) income from continuing operations per Common Unit – basic (0.29 ) 0.96 1.77 2.12 2.15 Net (loss) income per Common Unit – basic ( g) (0.26 ) 1.79 1.87 2.12 2.14 Net (loss) income per Common Unit – diluted (g) (0.26 ) 1.78 1.86 2.12 2.14 Cash distributions declared per unit $ 2.45 $ 2.41 $ 2.33 $ 2.28 $ 2.20 Balance Sheet Data (end of period) Cash and cash equivalents $ 14,411 $ 53,481 $ 15,765 $ 40,955 $ 36,494 Current assets 236,803 252,894 98,912 116,789 124,339 Total assets 965,597 992,007 670,559 700,146 723,006 Current liabilities, excluding short-term borrowings and current portion of long-term borrowings 194,987 202,024 94,802 98,606 119,196 Total debt 575,295 515,915 383,826 472,769 473,177 Other long-term liabilities 119,199 105,950 107,853 109,485 71,684 Partners' capital – Common Unitholders 159,199 238,880 165,950 103,680 105,549 Partner's capital – General Partner $ (1,779 ) $ 852 $ 1,567 $ 1,924 $ 1,888 Statement of Cash Flows Data Cash provided by (used in) Operating activities $ 39,005 $ 93,065 $ 57,300 $ 68,775 $ 101,838 Investing activities (24,631 ) (196,557 ) (4,859 ) (6,851 ) (17,907 ) Financing activities $ (53,444 ) $ 141,208 $ (77,631 ) $ (57,463 ) $ (59,082 ) Other Data Depreciation and amortization (h) $ 37,762 $ 36,743 $ 27,520 $ 28,355 $ 36,496 EBITDA (i) 107,105 131,882 110,020 117,907 129,977 Capital expenditures – maintenance and growth (j) 29,301 26,527 14,050 17,464 23,218 Acquisitions $ — $ 211,181 $ — $ — $ — Retail gallons sold Propane 516,040 537,330 491,451 455,988 524,728 Fuel oil and refined fuels 244,536 220,469 — — —
Year Ended(a) ---------------------------------------------------------------------------- September September September September September 27,Includes the results from our acquisition of substantially all of the assets and operations of Agway Energy from December 23, 2003, 28, 2002 29, 2001 30, 2000the date of acquisition.
(b) 25, 1999 -------- -------- -------- ------------ --------- STATEMENT OF OPERATIONS DATARevenues $ 771,679 $ 665,105 $ 931,536 $ 841,304 $ 620,207 CostsDuring fiscal 2005, we incurred $2.8 million in restructuring charges associated primarily with severance costs from an internal realignment of our field operations. During fiscal 2004, we incurred $2.9 million in restructuring charges to integrate our assets, employees and expenses 691,662 582,321 838,055 770,332 547,579 Recapitalization costsoperations with Agway Energy assets, employees and operations.
(c) - - - - 18,903 GainDuring fiscal 2005, we recorded a non-cash charge of $0.7 million related to the impairment of goodwill in our HVAC segment. During fiscal 2004, we recorded a non-cash charge of $3.2 million related to impairment of goodwill for one of our reporting units acquired in fiscal 1999.
(d) These amounts include, in addition to the gain on sale of assets - - - (10,328) - Gaincustomer service centers and the gain on sale of storage facility,- (6,768) - - - Income before interest expensegains from the disposal of property, plant andincome taxes (d) 80,017 89,552 93,481 81,300 53,725 Interest expense, net 33,629 35,325 39,596 42,534 31,218 Provisionequipment of $2.0 million forincome taxes 202 703 375 234 68 Income from continuing operations (d) 46,186 53,524 53,510 38,532 22,439 Discontinued operations:fiscal 2005, $0.7 million for fiscal 2004, $0.6 million for fiscal 2003, $0.5 million for fiscal 2002 and $3.8 million for fiscal 2001.
(e) During fiscal 2005, we incurred a one-time charge of $36.2 million as a result of our debt refinancing to reflect the loss on debt extinguishment associated with a prepayment premium of $32.0 million and the write-off of $4.2 million of unamortized bond issuance costs associated with the previously outstanding senior notes.
(f) Gain on sale of customer service centers (e) 2,483 - - - - Net income (d) 48,669 53,524 53,510 38,532 22,439 Incomefor fiscal 2005 of $1.0 million reflects the finalization of certain purchase price adjustments with the buyer of the customer service centers sold during fiscal 2004. Gain on sale of customer service centers for fiscal 2004 of $26.3 million reflects the sale of 24 customer service centers for net cash proceeds of approximately $39.4 million. Gain on sale of customer service centers for fiscal 2003 of $2.5 million reflects the sale of nine customer service centers for net cash proceeds of approximately $7.2 million. The gains on sale have been accounted for within discontinued operations pursuant to Statement of Financial Accounting Standards (‘‘SFAS’’) No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." Prior period results of operations attributable to the customer service centers sold in fiscal 2004 have been reclassified to remove financial results from continuing operations. Prior period results of operationsper Common Unit - basic 1.78 2.12 2.14 1.70 0.83 Netattributable to the customer service centers sold in fiscal 2003 were not significant and, as such, results prior to fiscal 2003 were not reclassified to remove financial results from continuing operations.
(g) Basic net (loss) income per Common Unit - basic (f) 1.87 2.12 2.14 1.70 0.83 Netis computed by dividing net (loss) income, after deducting our general partner's interest, by the weighted average number of outstanding Common Units. Diluted net income per Common Unit- diluted (f) 1.86 2.12 2.14 1.70 0.83 Cash distributions declared per unit $ 2.33 $ 2.28 $ 2.20 $ 2.11 $ 2.03 BALANCE SHEET DATA (END OF PERIOD) Cashis computed by dividing net income, after deducting our general partner's interest, by the weighted average number of outstanding Common Units andcash equivalents $ 15,765 $ 40,955 $ 36,494 $ 11,645 $ 8,392 Current assets 98,912 116,789 124,339 122,160 78,637 Total assets 665,630 700,146 723,006 771,116 659,220 Current liabilities, excluding current portion of long-term borrowings 94,802 98,606 119,196 124,585 99,953 Total debt 383,826 472,769 473,177 524,095 430,687 Other long-term liabilities 102,924 109,485 71,684 60,607 60,194 Partners' capital - Common Unitholders 165,950 103,680 105,549 58,474 66,342 Partner's capital - General Partner $ 1,567 $ 1,924 $ 1,888 $ 1,866 $ 2,044 STATEMENT OF CASH FLOWS DATA Cash provided by/(used in) Operating activities $ 57,300 $ 68,775 $ 101,838 $ 59,467 $ 81,758 Investing activities (4,859) (6,851) (17,907) (99,067) (12,241) Financing activities $ (77,631) $ (57,463) $ (59,082) $ 42,853 $(120,944) OTHER DATAtime vested restricted units granted under our 2000 Restricted Unit Plan.
(h) Depreciation and amortization (g) $ 27,520 $ 28,355 $ 36,496 $ 37,032 $ 34,453 EBITDA (h) 110,020 117,907 129,977 118,332 88,178 Capital expenditures (i) Maintenanceexpense for fiscal 2002 andgrowth 14,050 17,464 23,218 21,250 11,033 Acquisitions $ - $ - $ - $ 98,012 $ 4,768 Retail propane gallons sold 491,451 455,988 524,728 523,975 524,276subsequent fiscal years reflects our adoption of SFAS No. 142, ‘‘Goodwill and Other Intangible Assets’’ (‘‘SFAS 142’’) as of September 30, 2001 (the beginning of our 2002 fiscal year). SFAS 142 eliminated the requirement to amortize goodwill and certain intangible assets. Amortization expense for fiscal 2002 reflects approximately $7.4 million lower amortization expense compared to fiscal 2001 as a result of the elimination of amortization expense associated with goodwill.10(a) Our 2000 fiscal year contained 53 weeks. All other fiscal years contained 52 weeks. (b) Includes the results from our November 1999 acquisition of certain subsidiaries of SCANA Corporation, accounted for under the purchase method, from the date of acquisition. (c) We incurred expenses of $18.9 million in connection with the recapitalization transaction described in Note 1 to the consolidated financial statements included in this Annual Report. These expenses included $7.6 million representing cash expenses and $11.3 million representing non-cash charges associated with the accelerated vesting of restricted Common Units. (d) These amounts include, in addition to the gain on sale of assets and the gain on sale of storage facility, gains from the disposal of property, plant and equipment of $0.6 million for fiscal 2003, $0.5 million for fiscal 2002, $3.8 million for fiscal 2001, $1.0 million for fiscal 2000 and $0.6 million for fiscal 1999. (e) Gain on sale of customer service centers consists of nine customer service centers we sold during fiscal 2003 for total cash proceeds of approximately $7.2 million. We recorded a gain on sale of approximately $2.5 million, which has been accounted for within discontinued operations pursuant to Statement of Financial Accounting Standards ("SFAS") No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." Prior period results of operations attributable to these nine customer service centers were not significant and, as such, prior period results have not been reclassified to remove financial results from continuing operations. (f) Basic net income per Common Unit is computed by dividing net income, 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, after deducting our general partner's approximate 2% interest, by the weighted average number of outstanding Common Units and time vested restricted units granted under our 2000 Restricted Unit Plan. (g) Depreciation and amortization expense for the year ended September 28, 2002 reflects our early adoption of SFAS No. 142, "Goodwill and Other Intangible Assets" ("SFAS 142") as of September 30, 2001 (the beginning of our 2002 fiscal year). SFAS 142 eliminates the requirement to amortize goodwill and certain intangible assets. Amortization expense for the year ended September 28, 2002 reflects approximately $7.4 million lower amortization expense compared to the year ended September 29, 2001 as a result of the elimination of amortization expense associated with goodwill. (h)
(i) EBITDA represents net income before deducting interest expense, loss on debt extinguishment, 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. 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 generally accepted accounting principles (‘‘GAAP’’) and should not be considered as an alternative to net income or net cash provided by operating activities determined in accordance with GAAP. Because EBITDA 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 calculation of EBITDA and (ii) a reconciliation of EBITDA, as so calculated, to our net cash provided by operating activities (amounts in thousands):
Fiscal 2005 Fiscal 2004 Fiscal 2003 Fiscal 2002 Fiscal 2001 Net (loss) income $ (8,076 ) $ 54,304 $ 48,669 $ 53,524 $ 53,510 Add: Provision for income taxes 803 3 202 703 375 Loss on debt extinguishment 36,242 — — — — Interest expense, net 40,374 40,832 33,629 35,325 39,596 Depreciation and amortization 37,762 36,743 27,520 28,355 36,496 EBITDA 107,105 131,882 110,020 117,907 129,977 Add (subtract): Provision for income taxes (803 ) (3 ) (202 ) (703 ) (375 ) Loss on debt extinguishment (36,242 ) — — — — Interest expense, net (40,374 ) (40,832 ) (33,629 ) (35,325 ) (39,596 ) Gain on disposal of property, plant and equipment, net (2,043 ) (715 ) (636 ) (546 ) (3,843 ) Gain on sale of customer service centers (976 ) (26,332 ) (2,483 ) — — Gain on sale of storage facility — — — (6,768 ) — Changes in working capital and other assets and liabilities 12,338 29,065 (15,770 ) (5,790 ) 15,675 Net cash provided by (used in) Operating activities $ 39,005 $ 93,065 $ 57,300 $ 68,775 $ 101,838 Investing activities $ (24,631 ) $ (196,557 ) $ (4,859 ) $ (6,851 ) $ (17,907 ) Financing activities $ (53,444 ) $ 141,208 $ (77,631 ) $ (57,463 ) $ (59,082 )
(j) Our capital expenditures fall generally into two categories: (i) maintenance expenditures, which include expenditures for repair and replacement of property, plant and equipment; and (ii) growth capital expenditures which include new propane tanks and other equipment to facilitate expansion of our customer base and operating capacity.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following is a discussion of our financial condition and results of operations, which should be read in conjunction with our historical consolidated financial statements and notes thereto included elsewhere in this Annual Report.
Disclosure Regarding Forward-Looking Statements
This Annual Report on Form 10-K contains 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 the Partnership. Some of these statements can be identified by the use of forward-looking terminology such as ‘‘prospects,’’ ‘‘outlook,’’ ‘‘believes,’’ ‘‘estimates,’’ ‘‘intends,’’ ‘‘may,’’ ‘‘will,’’ ‘‘should,’’ ‘‘anticipates,’’ ‘‘expects’’ or ‘‘plans’’ or the negative or other variation of these or similar words, or by discussion of trends and conditions, strategies or risks and uncertainties. These Forward-Looking Statements involve certain risks and uncertainties that could cause actual results to differ materially from those discussed or implied in such Forward-Looking Statements (statements contained in this Annual Report identifying such risks and uncertainties are referred to as ‘‘Cautionary Statements’’). The risks and uncertainties and their impact on the Partnership’s results include, but are not limited to, the following risks:
• The impact of weather conditions on the demand for propane, fuel oil and other refined fuels, natural gas and electricity;
• Fluctuations in the unit cost of propane, fuel oil and other refined fuels and natural gas, and the impact of price increases on customer conservation;
• The ability of the Partnership to compete with other suppliers of propane, fuel oil and other energy sources;
• The impact on the price and supply of propane, fuel oil and other refined fuels from the political, military or economic instability of the oil producing nations, global terrorism and other general economic conditions;
• The ability of the Partnership to continue to realize, or to realize fully, within the expected timeframe, the expected cost savings and synergies from the Agway Acquisition (as defined below);
• The ability of the Partnership to acquire and maintain reliable transportation for its propane, fuel oil and other refined fuels;
• The ability of the Partnership to retain customers;
• The impact of energy efficiency and technology advances on the demand for propane and fuel oil;
• The ability of management to continue to control expenses, including the results of our recent field realignment initiative;
• The impact of changes in applicable statutes and government regulations, or their interpretations, including those relating to the environment and global warming and other regulatory developments on the Partnership’s business;
• The impact of legal proceedings on the Partnership’s business;
• The Partnership’s ability to implement its expansion strategy into new business lines and sectors; and
• The Partnership’s ability to integrate acquired businesses successfully. On different occasions, the Partnership or its representatives have made or may make Forward-Looking Statements in other filings with the SEC, press releases or oral statements made by or with the approval of one of the Partnership’s authorized executive officers. Readers are cautioned not to place undue reliance on Forward-Looking Statements, which reflect management’s view only as of the date made. The
Partnership undertakes no obligation to update any Forward-Looking Statement or Cautionary Statement. 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.
The following are factors that regularly affect our operating results and financial condition:
Product Costs
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 and fuel oil, is subject to volatile changes 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. 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 was experienced in fiscal 2005, 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 Partnership interests 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 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.
Risk Management
Product supply contracts are generally one-year agreements subject to annual renewal and generally permit suppliers to charge posted market prices (plus transportation costs) at the time of delivery or the current prices established at major delivery points. Since rapid increases in the cost of propane or fuel oil may not be immediately passed on to retail customers, such increases could reduce profitability. During fiscal 2005, approximately 70% of our fuel oil volumes were sold to individual customers under agreements pre-establishing a maximum price per gallon over a twelve-month period (the ‘‘Ceiling Program’’). While our strategy was to enter into derivative instruments in the form of futures and options traded on the NYMEX covering a majority of the fuel oil we expected to sell to customers under the
Ceiling Program in an effort to protect the margins under the program, we evaluated the costs of such hedge protection and elected not to hedge February through April deliveries under this program. After evaluating the costs to adequately hedge the Ceiling Program in the current commodity price environment, we decided to discontinue offering the Ceiling Program after the fiscal 2005 heating season.
We engage in risk management activities to reduce the effect of price volatility on our product costs and to help ensure the availability of product during periods of short supply. We are currently a party to propane and fuel oil futures contracts traded on the NYMEX and enter into forward and option agreements with third parties to purchase and sell propane at fixed prices in the future. 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. Risk management transactions may not always result in increased product margins. See Item 7A of this Annual Report.
Critical Accounting Policies and Estimates
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 legal 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.
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. We believe that the following are our critical accounting policies:
Revenue Recognition. We recognize revenue from the sale of propane, fuel oil and other refined fuels 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 our 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. In accordance with GAAP, actual results that differ from our assumptions are accumulated and amortized over future periods and therefore, generally affect our recognized expense and recorded obligation in such future periods. 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 obligations and our future expense. See ‘‘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. 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 covered by insurance.
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 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 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 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.
Derivative Instruments and Hedging Activities. See Item 7A of this Annual Report for information about accounting for derivative instruments and hedging activities.
Executive Summary of Results of Operations and Financial Condition
Fiscal 2005 presented a very challenging operating environment resulting from the combination of an erratic weather pattern and highly volatile commodity prices. While nationwide average temperatures, as reported by the National Oceanic and Atmospheric Administration (‘‘NOAA’’), were 7% warmer than normal in both fiscal 2005 and fiscal 2004, significantly warmer than normal temperatures during the critical months of the fiscal 2005 heating season (November 2004 through February 2005) had a significant negative impact on both propane and fuel oil volumes. Average temperatures during these critical months were 9% warmer than normal. In addition to the impact that warmer weather typically has on volumes, the combination of warm weather and high energy prices has led to increased customer conservation efforts.
In the commodities markets, the average posted prices of propane and fuel oil began a precipitous rise in September 2004, which continued to unprecedented levels during the heating season and continued with a counter-seasonal trend through the end of fiscal 2005, particularly in the fuel oil markets. Average posted prices of propane and fuel oil during fiscal 2005 increased 26% and 54%, respectively, compared to average posted prices in fiscal 2004. While propane margins remained strong, margin opportunities and therefore profitability in our refined fuels segment were severely restricted during the fiscal 2005 heating season as a result of our inability to pass on fully the rise in fuel oil prices due to our Ceiling Program, coupled with our decision not to hedge February through April 2005 deliveries under the Ceiling Program. Due to the extreme market volatility for fuel oil, the costs to hedge, in relation to the expected margins under this program, became prohibitive. The lost margin opportunity from this fuel oil Ceiling Program had the most significant negative impact on our financial results for fiscal 2005 accounting for an estimated impact of $21.5 million on the year-over-year comparison of operating margins in the fuel oil and refined fuels segment. After evaluating the costs to adequately hedge this program in the current price environment, management decided to discontinue offering the fuel oil Ceiling Program after the fiscal 2005 heating season.
In light of warmer weather and customer conservation efforts, retail propane gallons sold in fiscal 2005 decreased 21.3 million gallons, or 4.0%, to 516.0 million gallons from 537.3 million gallons in fiscal
2004. Sales of fuel oil and other refined fuels increased 24.0 million gallons, or 10.9%, to 244.5 million gallons, compared to 220.5 million gallons in the prior fiscal year. The negative impact of warm weather and high energy prices on volumes was partially offset by a full twelve months of Agway Energy operations in fiscal 2005 compared to nine months in fiscal 2004.
For fiscal 2005, we reported a net loss of $8.1 million, or ($0.26) per Common Unit, a decrease of $62.4 million, compared to net income of $54.3 million, or $1.79 per Common Unit, in fiscal 2004. We reported earnings before interest, loss on debt extinguishment, taxes, depreciation and amortization (‘‘EBITDA’’) of $107.1 million for fiscal 2005, a decrease of $24.8 million, or 18.8%, compared to $131.9 million in fiscal 2004.
In addition to the negative impact on our financial results from the fuel oil Ceiling Program, 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 recorded in the third quarter associated with our 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.
By comparison, EBITDA and net income for fiscal 2004 included the net favorable impact of $8.6 million and $7.6 million, respectively, from certain significant items mainly related to (i) a $26.3 million gain from the sale of 24 customer service centers in the northern and southern central regions of the United States considered to be non-strategic; (ii) a non-cash charge of $6.3 million included within cost of products sold related to the settlement of futures contracts which were marked-to-market under purchase accounting for the Agway Acquisition; (iii) a non-cash pension settlement charge of $5.3 million related to accelerated recognition of actuarial losses in our defined benefit pension plan; (iv) a non-cash charge of $3.2 million attributable to impairment of goodwill related to a small business acquired in 1999; (v) a $2.9 million restructuring charge related to integrating certain field management and back office functions in the northeast; and (vi) a non-cash charge of $1.0 million included within depreciation expense attributable to the write-down of assets to be disposed of as a result of our efforts to integrate certain northeast operations.
While the continued high price environment had a negative impact on our volumes as a result of customer conservation efforts and on the profitability of our refined fuels segment, our propane segment generated solid results despite the challenging environment. Profitability of our propane segment increased $3.5 million, or 2.4%, in fiscal 2005 compared to the prior year. Additionally, during the second half of fiscal 2005, we took positive steps to add financial flexibility and drive further efficiencies throughout our operations, highlighted by the successful completion of our debt refinancing and, more recently, the reorganization of our field operations to streamline our operating footprint and leverage our system infrastructure. In connection with our field realignment, we eliminated approximately 85 positions and have begun to consolidate customer service centers for further cost savings.
As we look ahead to fiscal 2006, with the continued integration of the Agway Energy operations, the operating efficiencies expected from our internal reorganization and the steps already taken to eliminate the fuel oil Ceiling Program, we believe we are well positioned for significant earnings growth in fiscal 2006. Our anticipated cash requirements for fiscal 2006 include: (i) maintenance and growth capital expenditures of approximately $30.0 million; (ii) approximately $40.0 million of interest payments; and, (iii) assuming distributions remain at the current level, approximately $76.6 million of distributions to Common Unitholders and the General Partner. The projected level of capital expenditures for fiscal 2006 is approximately $10.0 million higher than our expected annual level of capital spending in subsequent years, primarily as a result of anticipated spending on system enhancements and facility integration. Additionally, as our field realignment efforts continue into fiscal 2006 we may incur additional restructuring or asset impairment charges. Based on our current estimate of our cash position, availability under the Revolving Credit Agreement (unused borrowing capacity under the working capital facility of $76.3 million at November 28, 2005) 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 2005 Compared to Fiscal Year 2004
Revenues
(Dollars in thousands)
Fiscal 2005 Fiscal 2004 Increase Percent
IncreaseRevenues Propane $ 969,943 $ 856,109 $ 113,834 13.3 % Fuel oil and refined fuels 431,223 281,682 149,541 53.1 % Natural gas and electricity 102,803 68,452 34,351 50.2 % HVAC 106,115 92,072 14,043 15.3 % All other 10,150 8,939 1,211 13.5 % Total revenues $ 1,620,234 $ 1,307,254 $ 312,980 23.9 % Total revenues increased $313.0 million, or 23.9%, to $1,620.2 million for the year ended September 24, 2005 compared to $1,307.3 million for the year ended September 25, 2004 driven primarily by a significant increase in average selling prices in line with higher product costs, the inclusion of the Agway Energy operations for a full twelve months in fiscal 2005 compared to nine months in the prior year, offset to an extent by the impact on volumes from warmer weather. Retail sales volumes in our propane and fuel oil segments were negatively impacted by a combination of warmer than normal average nationwide temperatures, as well as the impact of customer conservation efforts from the significant rise in energy costs. As reported by NOAA, average nationwide temperatures in both fiscal 2005 and 2004 were 7% warmer than normal. However, the fiscal 2005 heating season presented a very erratic weather pattern with significantly warmer than normal temperatures during the critical months of the heating season (November 2004 through February 2005) offset somewhat by a burst of cold weather in March 2005. Average nationwide temperatures were 9% warmer than normal during these critical months in fiscal 2005.
Revenues in our propane segment of $969.9 million for the year ended September 24, 2005 increased $113.8 million, or 13.3%, compared to $856.1 million in the prior year. This increase is the result of higher average selling prices in line with higher commodity prices, offset to an extent by lower retail sales volumes attributable to the combination of warmer weather and customer conservation. Retail propane gallons sold decreased 21.3 million gallons, or 4.0%, to 516.0 million gallons in fiscal 2005 from 537.3 million gallons in the prior year. Average retail selling prices increased approximately 16.8% as a result of sustained higher commodity prices for propane. The average posted price of propane during fiscal 2005 increased approximately 26% 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 $37.0 million for the year ended September 24, 2005 which decreased $6.0 million, or 14.0%, compared to the prior year.
Revenues from the distribution of fuel oil and other refined fuels of $431.2 million for the year ended September 24, 2005 increased $149.5 million, or 53.1%, from $281.7 million in the prior year from a combination of increased volumes and significantly higher selling prices. Sales of fuel oil and other refined fuels amounted to 244.5 million gallons during fiscal 2005 compared to 220.5 million gallons in the prior year, an increase of 24.0 million gallons, or 10.9%, primarily reflecting the impact of the Agway Energy operations for a full twelve months in fiscal 2005 compared to nine months in the prior year, offset to an extent by the impact of warm weather and customer conservation. In addition, during the fourth quarter of fiscal 2004, we exited certain lower margin low sulfur diesel and gasoline businesses, thus negatively impacting the volume comparison year-over-year. Average fuel oil posted prices increased even more dramatically than propane prices throughout fiscal 2005 reaching unprecedented levels into the third and fourth quarters. For the year, average posted price of fuel oil increased 54% compared to the average posted prices in fiscal 2004. Average fuel oil selling prices increased approximately 28.6% as we were unable to pass on fully the significant rise in the commodity prices as a result of the fuel oil Ceiling Program (see below for the impact on cost of products sold).
Revenues in our natural gas and electricity segment for the year ended September 24, 2005 increased $34.4 million, or 50.2%, to $102.8 million compared to $68.5 million in the prior year. The increase is primarily attributable to higher average selling prices for both natural gas and electricity in line with higher product costs, as well as the impact of a full twelve months of operations in fiscal 2005. Revenues in our HVAC segment increased 15.3%, to $106.1 million in fiscal 2005 compared to $92.1 million in the prior year. The increase in HVAC revenues reflects the impact of a full twelve months from the Agway Energy operations, offset to an extent by lower service and installation activities during the last nine months of fiscal 2005 compared to the prior year.
Cost of Products Sold
(Dollars in thousands)
Fiscal 2005 Fiscal 2004 Increase/
(Decrease)Percent Increase/
(Decrease)Cost of products sold Propane $ 545,649 $ 453,869 $ 91,780 20.2 % Fuel oil and refined fuels 383,032 223,362 159,670 71.5 % Natural gas and electricity 90,461 59,950 30,511 50.9 % HVAC 42,650 36,267 6,383 17.6 % All other 5,456 5,581 (125 ) (2.2 %) Total cost of products sold $ 1,067,248 $ 779,029 $ 288,219 37.0 % As a percent of total revenues 65.9 % 59.6 % The cost of products sold reported in the consolidated statements of operations represents the weighted average unit cost of propane and fuel oil sold, as well as the cost of natural gas and electricity, including transportation costs to deliver product from our supply points to storage or to our customer service centers. Cost of products sold also includes the cost of appliances and related parts sold or installed by our customer service centers computed on a basis that approximates the average cost of the products. 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 increased $288.2 million, or 37.0%, to $1,067.2 million for the year ended September 24, 2005 compared to $779.0 million in the prior year. The increase results primarily from higher commodity prices for propane and fuel oil, coupled with the full year impact of the Agway Energy operations. Cost of products sold associated with the distribution of propane and related activities of $545.6 million increased $91.8 million, or 20.2%, compared to the prior year. Higher propane prices resulted in a $112.3 million increase in cost of products sold during fiscal 2005 compared to the prior year, partially offset by the 4.0% decline in propane volumes which had an impact of $15.9 million. Lower wholesale and risk management activities, noted above, decreased cost of products sold by $3.7 million compared to the prior year.
Cost of products sold associated with our fuel oil and refined fuels segment of $383.0 million for the year ended September 24, 2005 increased $159.7 million, or 71.5%, compared to the prior year. The impact of the unprecedented high commodity prices increased cost of products sold by $134.6 million during fiscal 2005 compared to the prior year and the increased volumes had an impact of $24.3 million. Cost of products sold in the prior year also included a $6.3 million non-cash charge associated with the settlement of futures contracts that were acquired in the Agway Acquisition. As the underlying futures and option contracts were settled, the derivative assets were charged to cost of products sold as an offset to the realized gains from contract settlement. The impact on cost of products sold represented a non-cash charge resulting from the application of purchase accounting on derivative instruments acquired.
While revenues increased 53.1%, margin opportunities and therefore profitability in our fuel oil and refined fuels segment were significantly restricted during our second and third quarters of fiscal 2005 as a result of our fuel oil Ceiling Program. We were unable in the prevailing high price environment to pass on fully the rise in fuel oil prices due to the restrictions of our fuel oil Ceiling Program, which
pre-established a maximum price per gallon, coupled with our decision not to hedge this pricing program for the February through April deliveries when confronted with unprecedented costs to properly hedge the program during that period. The lost margin opportunity from this fuel oil Ceiling Program had the most significant negative impact on our financial results for fiscal 2005 accounting for an estimated impact of $21.5 million on the year-over-year comparison of operating margins in the fuel oil and refined fuels segment. After evaluating the costs to adequately hedge this program in the current price environment, management decided to discontinue offering the fuel oil Ceiling Program after the fiscal 2005 heating season. Cost of products sold as a percentage of revenues in our fuel oil and refined fuels segment increased from 79.2% during fiscal 2004 to 88.4% in fiscal 2005 primarily as a result of our inability to pass on fully the unprecedented rise in fuel oil prices, coupled with the fact that February through April 2005 deliveries under the Ceiling Program were not hedged as the costs to hedge continued to be prohibitive due to market volatility.
In addition, the increase in revenues attributable to our natural gas and electricity and HVAC business segments had a $30.5 million and $6.4 million impact, respectively, on cost of products sold for the year ended September 24, 2005 compared to the prior year. Higher natural gas and electricity costs and higher volumes were the main attributes for the increase in our natural gas and electricity segment.
For the year ended September 24, 2005, cost of products sold represented 65.9% of revenues compared to 59.6% in the prior year. This increase results primarily from the impact of the fuel oil operations described above, as well as the continued impact of product mix with a full year of the non-propane Agway Energy operations.
Operating Expenses
(Dollars in thousands)
Fiscal 2005 Fiscal 2004 Increase Percent
IncreaseOperating expenses $ 396,235 $ 361,696 $ 34,539 9.5 % As a percent of total revenues 24.5 % 27.7 % All costs of operating our retail distribution and appliance sales and service operations are reported within operating expenses in the consolidated statements of operations. These operating expenses include the compensation and benefits of field and direct operating support personnel, costs of operating and maintaining our vehicle fleet, overhead and other costs of our purchasing, training and safety departments and other direct and indirect costs of our customer service centers. Changes in the fair value of derivative instruments that are not designated as hedges are recorded in current period earnings within operating expenses.
Operating expenses of $396.2 million for the year ended September 24, 2005 increased $34.5 million, or 9.5%, compared to $361.7 million in the prior year. Operating expenses for fiscal 2005 include a $2.5 million unrealized (non-cash) loss representing the net change in fair values of derivative instruments during the period, compared to a $4.5 million unrealized loss in the prior year (see Item 7A in this Annual Report for information on our policies regarding the accounting for derivative instruments). In addition to the non-cash impact of changes in the fair value of derivative instruments, the most significant impact on operating expenses was the increase in employee, vehicle and facility costs reflecting a full year of Agway Energy operations, offset to an extent by expense savings attributable to synergies in our northeast operations and continued expense management, particularly in light of lower operating results. Additionally, fiscal 2004 operating expenses included a $5.3 million non-cash pension charge in order to accelerate the recognition of a portion of unrecognized actuarial losses in our defined benefit pension plan. The accelerated recognition of these losses was recorded in accordance with SFAS No. 88 ‘‘Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits’’ (‘‘SFAS 88’’) as a result of an increase in the level of lump sum benefit payments made to retirees or terminated individuals during fiscal 2004 compared to prior years.
Operating expenses in fiscal 2005 increased primarily in the following areas: (i) employee compensation and benefit costs increased a net $21.1 million related to the impact of the Agway Energy
operations, partially offset by lower variable compensation from lower earnings; (ii) costs to operate our fleet increased $6.6 million primarily from higher fuel costs; (iii) operating costs at our customer service centers increased $12.6 million as a result of the full year inclusion of the Agway Energy operations; and, (iv) $1.0 million higher bad debt expense associated with the high energy price environment. These increases were offset to an extent by $4.8 million lower pension costs as a result of the non-cash settlement charge included in fiscal 2004 operating expenses described above.
General and Administrative Expenses
(Dollars in thousands)
Fiscal 2005 Fiscal 2004 Decrease Percent
DecreaseGeneral and administrative expenses $ 47,191 $ 53,888 $ (6,697 ) (12.4 %) As a percent of total revenues 2.9 % 4.1 % All costs of our back office support functions, including compensation and benefits for executives and other support functions, as well as other costs and expenses to maintain finance and accounting, treasury, legal, human resources, corporate development and the information systems functions are reported within general and administrative expenses in the consolidated statements of operations.
General and administrative expenses of $47.2 million for the year ended September 24, 2005 were $6.7 million, or 12.4%, lower compared to $53.9 million in fiscal 2004. The decrease was primarily attributable to a $7.7 million decline in compensation and benefit related expenses attributable to lower variable compensation in line with lower earnings, as well as the elimination of $4.2 million of costs incurred in fiscal 2004 in connection with transition services obtained on an interim basis following the Agway Acquisition and savings in other expense categories. These savings were offset somewhat by a $6.0 million increase in professional services fees associated primarily with our first-time compliance with the requirements of Section 404 of the Sarbanes-Oxley Act.
Restructuring Costs and Impairment of Goodwill. For the year ended September 24, 2005, we recorded a restructuring charge of $2.8 million related primarily to employee termination costs incurred as a result of actions taken during fiscal 2005. Specifically, during the fourth quarter of fiscal 2005 we approved and initiated a plan of reorganization to realign our field operations. This realignment is expected to generate further efficiencies, realize operating synergies and reduce costs at the field operating level. The restructuring charge consists primarily of costs associated with severance and other employee benefits for approximately 85 positions eliminated under the plan. During fiscal 2004, we recorded a $2.9 million restructuring charge for severance and other exit costs associated with vacating duplicative facilities and contract terminations in connection with the integration of Agway Energy operations and management.
Additionally, 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. During fiscal 2004, as a result of continued losses in one of our reporting units in our All Other segment acquired in fiscal 1999, we recorded a non-cash charge of $3.2 million related to goodwill impairment.
Depreciation and Amortization
(Dollars in thousands)
Fiscal 2005 Fiscal 2004 Increase Percent
IncreaseDepreciation and amortization $ 37,762 $ 36,743 $ 1,019 2.8 % As a percent of total revenues 2.3 % 2.8 % Depreciation and amortization expense for the year ended September 24, 2005 increased $1.0 million, or 2.8%, compared to the prior year primarily as a result of a full year of depreciation and amortization on the tangible and intangible assets acquired in the Agway Acquisition. Depreciation and amortization expense in fiscal 2005 included a $0.4 million asset impairment charge associated with steps
taken in the fourth quarter to realign our field operations, compared to a $1.0 million asset impairment charge in the prior year. In addition, fiscal 2005 included a non-cash charge of $0.8 million attributable to an impairment in the value of tradenames associated with our HVAC segment which were acquired in the Agway Acquisition.
Interest Expense
(Dollars in thousands)
Fiscal 2005 Fiscal 2004 Decrease Percent
DecreaseInterest expense, net $ 40,374 $ 40,832 $ (458 ) (1.1 %) As a percent of total revenues 2.5 % 3.1 % Net interest expense decreased $0.5 million, or 1.1%, to $40.4 million in fiscal 2005. The fiscal 2004 interest expense included a one-time fee of $1.9 million related to financing commitments for the Agway Acquisition. Interest expense in fiscal 2005 increased $1.4 million as a result of the net effect of a full year of interest on debt used to finance the December 2003 Agway Acquisition, offset to an extent by lower average interest rates due to our debt refinancing on March 31, 2005.
Discontinued Operations. As part of our overall business strategy, we continually monitor and evaluate our existing operations to identify opportunities to optimize return on assets employed by selectively consolidating or divesting operations in slower growing or non-strategic markets. In line with that strategy, during fiscal 2004, we sold 24 customer service centers for net cash proceeds of $39.4 million. We recorded a gain on sale of $26.3 million during fiscal 2004. During fiscal 2005, we 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. Gains on sale have been accounted for within discontinued operations in accordance with SFAS 144.
Net (Loss) Income and EBITDA. We reported a net loss of $8.1 million for the year ended September 24, 2005 compared to net income of $54.3 million in the prior year. Reported EBITDA for fiscal 2005 of $107.1 million decreased $24.8 million, or 18.8%, compared to $131.9 million in the prior year. 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 recorded in the third quarter associated with our 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 earnings was from the approximate $21.5 million impact on margin opportunities in our fuel oil business from the Ceiling Program. Income before interest expense, loss on debt extinguishment and income taxes in our propane and natural gas and electricity segments improved $3.5 million and $2.3 million, respectively.
By comparison, EBITDA and net income for fiscal 2004 included the net favorable impact of $8.6 million and $7.6 million, respectively, from the following significant items: (i) a $26.3 million gain from the sale of 24 customer service centers in the northern and southern central regions of the United States considered to be non-strategic; (ii) a non-cash charge of $6.3 million included within cost of products sold related to the settlement of futures contracts which were marked-to-market under purchase accounting for the Agway Acquisition; (iii) a non-cash pension settlement charge of $5.3 million related to accelerated recognition of actuarial losses in our defined benefit pension plan; (iv) a non-cash charge of $3.2 million attributable to impairment of goodwill related to a small business acquired in 1999; (v) a $2.9 million restructuring charge related to integrating certain field management and back office functions in the northeast; and (vi) a non-cash charge of $1.0 million included within depreciation expense attributable to the write-down of assets to be disposed of as a result of our efforts to integrate certain northeast operations.
EBITDA represents net income before deducting interest expense, loss on debt extinguishment, 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. Moreover, our
senior note agreements and our revolving credit agreement requireRevolving Credit Agreement requires us to use EBITDA as a component in calculating our leverage and interest coverage ratios. EBITDA is not a recognized term undergenerally accepted accounting principles ("GAAP")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 calculation of EBITDA and (ii) a reconciliation of EBITDA, as so calculated, to our net cash provided by operatingactivities (amountsactivities:(Dollars in thousands)
: 11
Fiscal Fiscal Fiscal Fiscal Fiscal 2003 2002 2001 2000 1999 ------------- --------------- --------------- -------------- ---------------Net income $ 48,669 $ 53,524 $ 53,510 $ 38,532 $ 22,439 Add: Provision for income taxes 202 703 375 234 68 Interest expense, net 33,629 35,325 39,596 42,534 31,218 Depreciation and amortization 27,520 28,355 36,496 37,032 34,453 ------------- --------------- --------------- -------------- --------------- EBITDA 110,020 117,907 129,977 118,332 88,178 ------------- --------------- --------------- -------------- --------------- Add/(subtract): Provision for income taxes (202) (703) (375) (234) (68) Interest expense, net (33,629) (35,325) (39,596) (42,534) (31,218) Gain on disposal of property, plant and equipment, net (636) (546) (3,843) (11,313) (578) Gain on sale of customer service centers (2,483) - - - - Gain on sale of storage facility - (6,768) - - - Changes in working capital and other assets and liabilities (15,770) (5,790) 15,675 (4,784) 25,444 ------------- --------------- --------------- -------------- --------------- Net cash provided by/(used in) Operating activities $ 57,300 $ 68,775 $ 101,838 $ 59,467 $ 81,758 ============= =============== =============== ============== =============== Investing activities $ (4,859) $ (6,851) $ (17,907) $ (99,067) $ (12,241) ============= =============== =============== ============== =============== Financing activities $ (77,631) $ (57,463) $ (59,082) $ 42,853 $ (120,944) ============= =============== =============== ============== ===============(i) Our capital expenditures fall generally into three categories: (i) maintenance expenditures, which include expenditures
Year Ended September 24,
2005September 25,
2004Net (loss) income $ (8,076 ) $ 54,304 Add: Provision for income taxes 803 3 Loss on debt extinguishment 36,242 — Interest expense, net 40,374 40,832 Depreciation and amortization 37,762 36,743 EBITDA 107,105 131,882 Add (subtract): Provision for income taxes (803 ) (3 ) Loss on debt extinguishment (36,242 ) — Interest expense, net (40,374 ) (40,832 ) Gain on disposal of property, plant and equipment, net (2,043 ) (715 ) Gain on sale of customer service centers (976 ) (26,332 ) Changes in working capital and other assets and liabilities 12,338 29,065 Net cash provided by (used in) Operating activities $ 39,005 $ 93,065 Investing activities $ (24,631 ) $ (196,557 ) Financing activities $ (53,444 ) $ 141,208 Fiscal Year 2004 Compared to Fiscal Year 2003
Revenues
(Dollars in thousands)
Fiscal 2004 Fiscal 2003 Increase Percent
IncreaseRevenues Propane $ 856,109 $ 680,840 $ 175,269 25.7 % Fuel oil and refined fuels 281,682 — 281,682 100 % Natural gas and electricity 68,452 — 68,452 100 % HVAC 92,072 46,938 45,134 96.2 % All other 8,939 7,297 1,642 22.5 % Total revenues $ 1,307,254 $ 735,075 $ 572,179 77.8 % Total revenues increased $572.2 million, or 77.8%, to $1,307.3 million for
repair and replacement of property, plant and equipment; (ii) growth capital expenditures which include new propane tanks and other equipmentthe year ended September 25, 2004 compared tofacilitate expansion of our customer base and operating capacity; and (iii) acquisition capital expenditures, which include expenditures related to$735.1 million for theacquisition of propane and other retail operations and a portion of the purchase price allocated to intangible assets associated with such acquired businesses. 12ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following is a discussion of our financial condition and results of operations, which should be read in conjunction with our historical consolidated financial statements and notes thereto included elsewhere in this Annual Report. Since our Operating Partnership and Service Company account for substantially all of our assets, revenues and earnings, a separate discussion of results of operations from our other subsidiaries is not presented. DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS This Annual Report on Form 10-K contains Forward-Looking Statements as defined in the Private Securities Litigation Reform Act of 1995 relating to our future business expectations and predictions and financial condition and results of operations. Some of these statements can be identifiedyear ended September 27, 2003 driven primarily by theuse 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 Cautionary Statements. The risks and uncertainties and their impact on our operations include, but are not limited to, the following risks: o The impact of weather conditions on the demand for propane; o Fluctuations in the unit cost of propane; o Our ability to compete with other suppliers of propane and other energy sources; o The impact on propane prices and supply from the political and economic instability of the oil producing nations and other general economic conditions; o Our ability to retain customers; o The impact of energy efficiency and technology advances on the demand for propane; o The ability of management to continue to control expenses; o The impact of regulatory developments on our business; o The impact of legal proceedings on our business; o Our ability to implement our expansion strategy into new business lines and sectors; o Our ability to integrate acquired businesses successfully. On different occasions, we or our representatives have made or may make Forward-Looking Statements in other filings that we make with the SEC, in press releases or in oral statements made by or with the approval of one of our authorized executive officers. Readers are cautioned not to place undue reliance on Forward-Looking or Cautionary Statements, which reflect management's opinions only as of the date hereof. We undertake no obligation to update any Forward-Looking or Cautionary Statement. All subsequent written and oral Forward-Looking Statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the Cautionary Statements in this Annual Report and in future SEC reports. The following are factors that regularly affect our operating results and financial condition: PRODUCT COSTS The level of profitability in the retail propane business is largely dependent on the difference between retail sales price and product cost. The unit cost of propane is subject to volatile changes 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. Propane unit 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 13Agwaysignificantly from year to year as product costs fluctuate with propane, crude oil and natural gas commodity market conditions. SEASONALITY The retail propane distribution business is seasonal because of propane's 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. Consequently, sales and operating profits are concentratedAcquisition. Revenues in our
first and second fiscal quarters. Cash flows from operations, therefore, are greatest duringpropane segment of $856.1 million for thesecond and third fiscal quarters when customers pay for propane purchased during the winter heating season. Lower operating profits and either net lossesyear ended September 25, 2004 increased $175.3 million, orlower net income during the period from April through September (our third and fourth fiscal quarters) are expected. To the extent necessary, we will reserve cash from the second and third quarters for distribution to Unitholders in the first and fourth fiscal quarters. WEATHER Weather conditions have a significant impact on the demand for propane for both heating and agricultural purposes. Many of our customers rely heavily on propane as a heating fuel. Accordingly, the volume of propane 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 use, while sustained colder-than-normal temperatures will tend to result in greater propane use. RISK MANAGEMENT Product supply contracts are generally one-year agreements subject to annual renewal and generally permit suppliers to charge posted market prices (plus transportation costs) at the time of delivery or the current prices established at major delivery points. Since rapid increases in the cost of propane may not be immediately passed on to retail customers, such increases could reduce profit margins. We engage in risk management activities to reduce the effect of 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 contracts traded on the New York Mercantile Exchange and enter into forward and option agreements with third parties to purchase and sell propane at fixed prices in the future. Risk management activities are monitored by management through enforcement of our Commodity Trading Policy and reported to our Audit Committee. Risk management transactions may not always result in increased product margins. See additional discussion in Item 7A of this Annual Report. CRITICAL ACCOUNTING POLICIES AND ESTIMATES Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated, requiring management to make certain assumptions with respect to values or conditions that cannot be known with certainty at the time the financial statements are prepared. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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 legal reserves, allowance for doubtful accounts, asset valuation assessment 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 14give rise to the revision become known to us. 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. We believe that the following are our critical accounting policies: REVENUE RECOGNITION. We recognize revenue from the sale of propane 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 repair and maintenance activities is recognized upon completion of the service. ALLOWANCE 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 allowance for doubtful accounts using a specific reserve for known or anticipated uncollectible accounts, as well as a general 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. In accordance with generally accepted accounting principles, actual results that differ from our assumptions are accumulated and amortized over future periods and therefore, generally affect our recognized expense and recorded obligation in such future periods. 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 obligations and our future expense. See "Pension Plan Assets" below for additional disclosure regarding pension and other postretirement 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 or the amount of the deductible, whichever is lower, utilizing actuarially determined loss development factors applied to actual historical claims data. 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 the respective reporting unit. Fair value of the reporting unit is estimated using either (i) a market value approach taking into consideration the quoted market price of our Common Units; or (ii) 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 additional information about accounting for derivative instruments and hedging activities. 15RESULTS OF OPERATIONS FISCAL YEAR 2003 COMPARED TO FISCAL YEAR 2002 - ---------------------------------------------- REVENUES. Revenues increased 16.0%25.7%,or $106.6 million, to $771.7 million in fiscal 2003compared to$665.1 million in fiscal 2002. Revenues from retail propane activities increased $130.0 million, or 24.3%, to $664.2 million in fiscal 2003 compared to $534.2$680.8 million in the prior year. This increasewasis the result ofan increase in averagehigher retail and wholesale propaneselling prices,sales volumes, coupled with an increase inretail gallons sold. Propaneaverage selling pricesaveraged 15.9%in line with higherin fiscal 2003 comparedcommodity prices for propane. Despite nationwide average temperatures, as reported by NOAA, that were 7% warmer than normal and 8% warmer than the prior year, retail propane gallons sold increased 45.8 million gallons, or 9.3%, to 537.3 million gallons for the year ended September 25, 2004. The increase is primarily attributable to theprior yearaddition of Agway Energy volumes from December 23, 2003, partially offset by the effect of the warmer temperatures. Average selling prices increased approximately 12.5% as a result ofsteadily increasing costssustained higher commodity prices for propane. The average posted price of propanethroughout the first half ofduring fiscal2003 which remained higher during the second half of the year. Retail gallons sold2004 increased35.5 million gallons, or 7.8%, to 491.5 million gallons in fiscal 2003approximately 23% compared to456.0 million gallons in fiscal 2002 due primarily to colderthe averagetemperatures experienced in parts of our service area, particularly during the six month peak heating season from October 2002 through March 2003. Temperatures nationwide, as reported by the National Oceanic and Atmospheric Administration ("NOAA"), averaged 1% colder than normal in fiscal 2003 compared to 13% warmer than normal temperaturesposted prices in the prioryear, or 14% colder conditions year-over-year. The coldest weather conditions, however, were experienced inyear. Additionally, included within theeastern and central regions of the United States. In the west, average temperatures were 10% warmer than normal during fiscal 2003, compared to 7% warmer than normal during the prior year. In addition, our volumes continue to be affected by the impact of a continued economic recession on customer buying habits. Revenuespropane segment are revenues from wholesale and risk management activities of$16.6$43.0 million for the year ended September 25, 2004 which increased $26.4 million, compared to the prior year.Revenue contribution from our fuel oil and other refined fuels and our natural gas and electricity segments amounted to $281.7 million and $68.5 million, respectively, for the year ended September 25, 2004 from the addition of Agway Energy since December 23, 2003. Total fuel oil and other refined fuel gallons sold in fiscal
2003 decreased $19.52004 amounted to 220.5 millionor 54.0%,gallons. Revenues from our HVAC service and installation activities, as well as from sales of HVAC equipment and related parts, of $92.1 million for the year ended September 25, 2004 increased $45.1 million compared torevenues of $36.1 million inthe prior year, primarilyas a resultdue to the addition oflower volumes sold in the wholesale market in line with our strategy to reduce our emphasis on wholesale activities. Revenue from other sources, including sales of appliances and related parts and services, of $90.9 million in fiscal 2003 decreased $3.9 million, or 4.1%, compared to other revenue in the prior year of $94.8 million. The decrease in other revenues was primarily attributable to lower revenues from service and installations. COST OF PRODUCTS SOLD. The cost of products sold reported in the consolidated statements of operations represents the weighted average unit cost of propane sold, including transportation costs to deliver product from our supply points to storage or to our customer service centers.Agway Energy.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. Cost of products sold is reported exclusive of any depreciation and amortization as such amounts are reported separately within the consolidated statements of operations.Products Sold(Dollars in thousands)
Fiscal 2004 Fiscal 2003 Increase Percent
IncreaseCost of products sold Propane $ 453,869 $ 332,132 $ 121,737 36.7 % Fuel oil and refined fuels 223,362 — 223,362 100 % Natural gas and electricity 59,950 — 59,950 100 % HVAC 36,267 22,035 14,232 64.6 % All other 5,581 4,415 1,166 26.4 % Total cost of products sold $ 779,029 $ 358,582 $ 420,447 117.3 % As a percent of total revenues 59.6 % 48.8 % Cost of products sold increased
$87.7$420.4 millionor 30.3%,to$376.8$779.0 millionin fiscal 2003for the year ended September 25, 2004 compared to$289.1$358.6 million in the prior year. The increase results primarily froma $93.0 million impact fromtheaforementionedincrease in retail propane volumes sold, as well as thecommodity priceaddition ofpropane resulting infuel oil and other refined fuel sales volumes, which had a39.4% increase incombined impact of $246.2 million on theaverage unityear-over-year comparison of cost of products sold. Higher commodity prices for propaneinduring fiscal20032004 also increased cost of products sold by $65.9 million compared to the prioryear, coupled with the aforementioned increase in retail volumes sold resulting in an increase of $17.0 million; offset by a $21.2 million decrease from the decline inyear. Increased wholesale and risk management activities,described above.noted above, increased cost of products sold by $26.7 million compared to the prior year.Cost of products sold for the year ended September 25, 2004 also included a $6.3 million non-cash charge associated with the settlement of futures contracts that were acquired in the Agway Acquisition. As the underlying futures and option contracts were settled, the derivative assets were charged to cost of products sold as an offset to the realized gains from contract settlement. The impact on cost of products sold represents a non-cash charge resulting from the application of purchase accounting on derivative instruments acquired. In
fiscal 2003,addition, the increase in revenues attributable to our natural gas and electricity and HVAC business segments had a $60.0 million and $14.2 million impact, respectively, on cost of products sold in the year ended September 25, 2004 compared to the prior year.For the year ended September 25, 2004, cost of products sold represented
48.8%59.6% of revenues compared to43.5%48.8% in the prior year.TheThis increaseinresults primarily from thecostdifferent mix of products soldduring fiscal 2004 as a result of the additional product offerings from the Agway Energy operations. Generally, the prices for fuel oil and other refined fuels as a percentage of product revenues
relates primarilytend tosteadily increasingbe between 20% and 30% higher than propane costs are as a percentage of propaneduringrevenues.Operating Expenses
(Dollars in thousands)
Fiscal 2004 Fiscal 2003 Increase Percent
IncreaseOperating expenses $ 361,696 $ 232,462 $ 129,234 55.6 % As a percent of total revenues 27.7 % 31.6 % Operating expenses of $361.7 million for the
first half of fiscal 2003 which remained higher during the second half of fiscal 2003year ended September 25, 2004 increased $129.2 million, or 55.6%, compared tosteadily declining product costs$232.5 million in the prior year.OPERATING EXPENSES. All costs of operating our retail propane 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 our customer service centers.Operating expensesincreased 7.1%, or $16.6 million, to $250.7 million infor fiscal2003 compared to $234.1 million in fiscal 2002. Operating expenses in fiscal 20032004 include a$1.5$4.5 million unrealized (non-cash) loss representing the net change in fair16values of derivative instruments during the period, compared to a $5.4$1.5 million unrealized(non-cash) gainloss in the prior year (see Item 7A- Quantitative and Qualitative Disclosures About Market Riskin this Annual Report for information on our policies regarding the accounting for derivative instruments). In addition to the$6.9 millionnon-cash impact of changes in the fair value of derivative instruments,year-over-year,the most significant impact on operating expenses was the impact on employee, vehicle and facility costs from the addition of the Agway Energy operations. Additionally, fiscal 2004 operating expenses include a $5.3 million non-cash pension charge in order to accelerate the recognition of a portion of unrecognized actuarial losses in our defined benefit pension plan. The accelerated recognition of these losses was a result of an increase in the level of lump sum benefit payments made to retirees or terminated individuals during fiscal 2004 compared to prior years.Operating expenses in fiscal 2004 increased
$9.7primarily in the following areas: (i) employee compensation and benefit costs increased $51.6 millionprimarily resulting from (i) $2.3 millionrelated to an increase in field personnel and increasedpension costs,earnings; (ii)$2.2 million higher insurance costs, (iii) $2.1 million highercosts to operate our fleetprimarily fromincreasedfuel$9.2 million; (iii) operating costsand (iv) $0.9at our customer service centers increased $42.0 millionhigher employee compensation and benefits to support the increased sales volume. In addition, we experienced $2.1 million higher bad debt expenseas a result of thesignificant increaseaddition of the Agway Energy operations; (iv) pension costs increased $7.4 million primarily as a result of the $5.3 million non-cash charge described above; (iv) insurance costs increased $13.2 million; and, (v) medical costs increased $2.9 million.General and Administrative Expenses
(Dollars in
the commodity price of propane resulting in higher prices to our customers, higher sales volumes and general economic conditions. GENERAL AND ADMINISTRATIVE EXPENSES. All costs of our back office support functions, including compensation and benefits for executives and other support functions, as well as other costs and expenses to maintain finance and accounting, treasury, legal, human resources, corporate development and the information systems functions are reported within general and administrative expenses in the consolidated statements of operations.thousands)
Fiscal 2004 Fiscal 2003 Increase Percent
IncreaseGeneral and administrative expenses $ 53,888 $ 36,661 $ 17,227 47.0 % As a percent of total revenues 4.1 % 5.0 % General and administrative expenses of $53.9 million for the year ended September 25, 2004 were $17.2 million, or 47.0%, higher compared to $36.7 million
forin fiscal2003 were $5.9 million, or 19.2%, higher than fiscal 2002 expenses of $30.8 million.2003. The increase was primarily attributable to the impact of$2.8$10.4 million higher employee compensation and benefitrelatedcosts as a result of higher earnings and increased overall headcount, as well as$1.2$4.2 millionhigherrelated to transition services fees paid to Agway, Inc. for back office support provided subsequent to the Agway Acquisition. In addition, we incurred anticipated increases in marketing, professional services and travel expenses during fiscal 2004 associated with our efforts to acquire Agway Energy during the first quarter and in connection with our integration efforts during the remainder of fiscal 2004.Restructuring Costs and Impairment of Goodwill. During fiscal 2004, we recorded a $2.9 million restructuring charge for severance and other exit costs associated with vacating duplicative facilities and contract terminations in connection with the integration of Agway Energy operations and management. While the majority of restructuring and integration activities were completed by the end of fiscal 2004, there may be additional charges in fiscal 2005 as we continue to finalize our operating footprint in the
current year period. DEPRECIATION AND AMORTIZATION.northeast. Additionally, during the third quarter of fiscal 2004, as a result of continued losses in one of our reporting units acquired in fiscal 1999, we recorded a non-cash charge of $3.2 million related to goodwill impairment.Depreciation and Amortization
(Dollars in thousands)
Fiscal 2004 Fiscal 2003 Increase Percent
IncreaseDepreciation and amortization $ 36,743 $ 27,520 $ 9,223 33.5 % As a percent of total revenues 2.8 % 3.7 % Depreciation and amortization expense
decreased $0.9increased 33.5% to $36.7 millionor 3.2%,for the year ended September 25, 2004 compared to $27.5 million for the prior year, primarily as a result of the additional depreciation and amortization associated with the acquired tangible and intangible assets from the Agway Acquisition. In addition, depreciation expense for fiscal 2004 included a $1.0 million non-cash charge related to assets abandoned as a result of our facility integration efforts infiscal 2003,the northeast.Interest Expense
(Dollars in thousands)
Fiscal 2004 Fiscal 2003 Increase Percent
IncreaseInterest expense, net $ 40,832 $ 33,629 $ 7,203 21.4 % As a percent of total revenues 3.1 % 4.6 % Net interest expense increased $7.2 million, or 21.4%, to $40.8 million for the year ended September 25, 2004, compared to
$28.4$33.6 million infiscal 2002. GAIN ON SALE OF STORAGE FACILITY. On January 31, 2002 (thethe prior year. The increase results primarily from the net impact of the addition of $175.0 million of 6.875% senior notes associated with financing for the Agway Acquisition, offset by a reduction in amounts outstanding under our 7.54% senior notes due to repayment of the second annual principal payment of $42.5 million during the fourth quarter of fiscal2002),2003 and of the third annual principal payment of $42.5 million during the fourth quarter of fiscal 2004, in both cases using cash on hand. In addition, we incurred a one-time fee of $1.9 million related to financing commitments for the Agway Acquisition during the first quarter of fiscal 2004 which is included within fiscal 2004 interest expense.Discontinued Operations. During fiscal 2004, we sold
our 170 million gallon propane storage facility in Hattiesburg, Mississippi, which was considered a non-strategic asset,24 customer service centers for net cash proceeds of$8.0 million, resulting in$39.4 million. We recorded a gain on sale ofapproximately $6.8$26.3 million during fiscal 2004. During fiscal 2003, we sold nine customer service centers for net cash proceeds of $7.2 million and recorded a gain on sale of $2.5 million.INCOME BEFORE INTEREST EXPENSE AND INCOME TAXES ANDGains on sale have been accounted for within discontinued operations in accordance with SFAS 144.Net Income and EBITDA.
Income before interest expense andNet incometaxes decreased $9.6of $54.3 million for the year ended September 25, 2004 increased $5.6 million, or10.7%11.5%,to $80.0 million in fiscal 2003compared to$89.6$48.7 million in the prior year.Earnings before interest, taxes, depreciation and amortization ("EBITDA") amountedWe reported record EBITDA of $131.9 million for the year ended September 25, 2004, compared to $110.0million for fiscal 2003 compared to $117.9million for the prior year,a declinean increase of$7.9$21.9 million, or6.7%19.9%.The decline inNet incomebefore interest expenseandincome taxes and inEBITDAover the prior year reflects the impact of 7.8% higher retail volumes sold, offsetfor fiscal 2004 were favorably impacted by the$6.9 million unfavorable impactnet result ofmark-to-market activity on derivative instruments year-over-year included within operating expenses,certain significant items, mainly relating to: (i) the$6.8$26.3 million gainonfrom the sale ofour Hattiesburg, Mississippi storage facility impacting prior year results24 customer service centers considered to be non-strategic, primarily located in the northern and southern central regions of thehigher combined operating and general and administrative expenses (described above) in support of higher business activity. Additionally, theUnited States, compared to a $2.5 million gainreportedfrom the sale of nine customer service centers during fiscal2003, reported2003; (ii) the non-cash charge of $6.3 million included withindiscontinuedcost of products sold relating to the settlement of futures contracts which were marked-to-market under purchase accounting for the Agway Acquisition; (iii) the non-cash pension charge of $5.3 million related to accelerated recognition of actuarial losses as a result of the level of lump sum benefit payments in fiscal 2004; (iv) the non-cash charge of $3.2 million attributable to the impairment of goodwill related to a small business acquired in 1999; (v) the $2.9 million restructuring charge related to our efforts to integrate certain management and back office functions of Agway Energy; and, (vi) the non-cash charge of $1.0 million included within depreciation expense attributable to the write-down of assets to be disposed of as a result of the blending of field operations in the northeast. These significant items had afavorablenet positive impact of $6.1 million and $5.1 million onfiscal 2003 EBITDA.the year-over-year comparison of EBITDArepresentsand net income,before deducting interest expense, income taxes, depreciation and amortization.respectively, for the year ended September 25, 2004.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. Moreover, our
senior note agreements and our revolving credit agreement requireRevolving Credit Agreement requires us to use EBITDA as a component in calculating our leverage and interest coverage ratios. EBITDA is not a recognized term undergenerally accepted accounting principles ("GAAP")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 calculation of EBITDA and (ii) a reconciliation of EBITDA, as so calculated, to our net cash provided by operatingactivities (amountsactivities:(Dollars in thousands)
: 17
Year Ended ------------------------------------------- September 27, September 28, 2003 2002 ------------------ -------------------Net income $ 48,669 $ 53,524 Add: Provision for income taxes 202 703 Interest expense, net 33,629 35,325 Depreciation and amortization 27,520 28,355 ------------------ ------------------- EBITDA 110,020 117,907 ------------------ ------------------- Add/(subtract): Provision for income taxes (202) (703) Interest expense, net (33,629) (35,325) Gain on disposal of property, plant and equipment, net (636) (546) Gain on sale of customer service centers (2,483) - Gain on sale of storage facility - (6,768) Changes in working capital and other assets and liabilities (15,770) (5,790) ------------------ ------------------- Net cash provided by/(used in) Operating activities $ 57,300 $ 68,775 ================== =================== Investing activities $ (4,859) $ (6,851) ================== =================== Financing activities $ (77,631) $ (57,463) ================== ===================INTEREST EXPENSE. Net interest expense decreased $1.7 million, or 4.8%, to $33.6 million in fiscal 2003 compared to $35.3 million in fiscal 2002. The decrease in interest expense reflects the positive steps taken by us during the third quarter
Year Ended September 25,
2004September 27,
2003Net income $ 54,304 $ 48,669 Add: Provision for income taxes 3 202 Interest expense, net 40,832 33,629 Depreciation and amortization 36,743 27,520 EBITDA 131,882 110,020 Add (subtract): Provision for income taxes (3 ) (202 ) Interest expense, net (40,832 ) (33,629 ) Gain on disposal of property, plant and equipment, net (715 ) (636 ) Gain on sale of customer service centers (26,332 ) (2,483 ) Changes in working capital and other assets and liabilities 29,065 (15,770 ) Net cash provided by (used in) Operating activities $ 93,065 $ 57,300 Investing activities $ (196,557 ) $ (4,859 ) Financing activities $ 141,208 $ (77,631 ) Liquidity and Capital Resources
Analysis of
fiscal 2003 to lower our overall leverage, which resulted in an $88.9 million reduction in debt, coupled with lower average interest rates on outstanding borrowings under our Revolving Credit Agreement during the first and second quarters of fiscal 2003. DISCONTINUED OPERATIONS. As part of our overall business strategy, we continually monitor and evaluate our existing operations to identify opportunities that will allow us to optimize our return on assets employed by selectively consolidating or divesting operations in slower growing or non-strategic markets. In line with that strategy, we sold nine customer service centers during fiscal 2003 for total cash proceeds of approximately $7.2 million. We recorded a gain on sale of approximately $2.5 million, which has been accounted for within discontinued operations pursuant to SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." FISCAL YEAR 2002 COMPARED TO FISCAL YEAR 2001 - --------------------------------------------- REVENUES. Revenues of $665.1 million in fiscal 2002 decreased $266.4 million, or 28.6%, compared to $931.5 million in fiscal 2001. Revenues from retail propane activities decreased $219.2 million, or 29.1%, to $534.2 million in fiscal 2002 compared to $753.4 million in fiscal 2001. This decrease is principally due to a decrease in average selling prices, coupled with a decrease in retail gallons sold. Average selling prices declined 18.4% as a result of a significant decline in the commodity price of propane in fiscal 2002 compared to the prior year. Retail gallons sold decreased 13.1%, or 68.7 million gallons, to 456.0 million gallons in fiscal 2002 compared to 524.7 million gallons in fiscal 2001. The decrease in volume was attributable to record warm weather conditions which were most dramatic during the peak heating months of October through March of fiscal 2002 as well as, to a lesser extent, the impact of the economic recession on commercial and industrial customers' buying habits. Nationwide temperatures during fiscal 2002 were 13% warmer than normal as compared to temperatures that were 2% colder than normal during fiscal 2001, as reported by NOAA. During the peak heating months of October 2001 through March 2002, temperatures nationwide were 13% warmer than normal as compared to 5% colder than normal in the comparable period in fiscal 2001, as reported by NOAA. Volumes from the components of our customer mix that are less weather sensitive declined approximately 12% year-over-year. 18Revenues from wholesale and risk management activities decreased $50.1 million, or 58.1%, to $36.1 million in fiscal 2002 compared to $86.2 million in fiscal 2001. A less volatile commodity price environment for propane during fiscal 2002 compared to fiscal 2001 resulted in reduced risk management activities and lower volumes in the wholesale market. Revenue from other sources, including sales of appliances and related parts and services, of $94.8 million in fiscal 2002 increased $2.9 million, or 3.2%, over fiscal 2001 revenues of $91.9 million. COST OF PRODUCTS SOLD. Cost of products sold decreased $221.2 million, or 43.3%, to $289.1 million in fiscal 2002 compared to $510.3 million in fiscal 2001. The decrease results primarily from a $125.1 million impact from the aforementioned decrease in the commodity price of propane resulting in a 36.3% decrease in the average unit cost of propane during fiscal 2002 compared to fiscal 2001. This is coupled with the aforementioned decrease in retail volumes sold resulting in a decrease of $51.9 million, and a $45.4 million decrease from the decline in wholesale and risk management activities described above. In fiscal 2002, cost of products sold represented 43.5% of revenues compared to 54.8% in the prior year. The decrease in the cost of products sold as a percentage of revenues relates primarily to steadily decreasing costs of propane during fiscal 2002. OPERATING EXPENSES.Cash FlowsOperating
expenses decreased 9.5%, or $24.6 million, to $234.1 million in fiscal 2002 compared to $258.7 million in fiscal 2001. Operating expenses for the year ended September 28, 2002 include a $5.4 million unrealized (non-cash) gain representing the net change in fair values of derivative instruments not designated as hedges, compared to a $3.1 million unrealized loss in fiscal 2001 (see Item 7A of this Annual Report for information on our policies regarding the accounting for derivative instruments and hedging activities). In addition to the $8.5 million favorable impact from changes in the fair value of derivative instruments year-over-year, operating expenses decreased $16.1 million, or 6.3%, principally attributable to our ability to reduce costs amidst declining volumes resulting from ongoing initiatives to shift costs from fixed to variable, primarily in the areas of employee compensation and benefits. The lower compensation costs of $10.5 million were offset, in part, by a $4.0 million increase in medical and dental costs in fiscal 2002 compared to the prior year. Additionally, operating expenses were favorably impacted by a $4.2 million decrease in provisions for doubtful accounts and $3.0 million lower costs of operating our fleet, including maintenance and fuel costs, in fiscal 2002 compared to fiscal 2001. Provisions for doubtful accounts were higher in fiscal 2001 primarily as a result of the generally higher selling price environment driven by the higher average propane costs. GENERAL AND ADMINISTRATIVE EXPENSES. General and administrative expenses decreased $1.7 million, or 5.2%, to $30.8 million in fiscal 2002 compared to $32.5 million in fiscal 2001, again attributable to a decrease in employee compensation and benefit costs of $4.3 million, as well as to a $1.6 million decrease in fees for professional services, partly offset by a $1.3 million increase in telecommunication costs. DEPRECIATION AND AMORTIZATION. Depreciation and amortization expense decreased 22.2%, or $8.1 million, to $28.4 million in fiscal 2002 compared to $36.5 million in the prior year primarily as a result of our decision to early adopt SFAS 142 effective September 30, 2001 (the beginning of fiscal 2002), which eliminated the requirement to amortize goodwill and certain intangible assets. If SFAS 142 had been in effect at the beginning of the prior year, fiscal 2001 net income would have improved by $7.4 million. GAIN ON SALE OF STORAGE FACILITY. On January 31, 2002, we sold our 170 million gallon propane storage facility in Hattiesburg, Mississippi, which was considered a non-strategic asset, for net cash proceeds of $8.0 million, resulting in a gain on sale of approximately $6.8 million. INCOME BEFORE INTEREST EXPENSE AND INCOME TAXES AND EBITDA. Income before interest expense and income taxes decreased 4.2%, or $3.9 million, to $89.6 million compared to $93.5 million in the prior year. Earnings before interest, taxes, depreciation and amortization ("EBITDA") decreased 9.3%, or $12.1 million, to $117.9 million in fiscal 2002 compared to $130.0 million in the prior year. The decreases in income before interest expense and 19Due to the seasonal nature of the propane income taxes and in EBITDA reflect the impact of the 13.1% lower retail volumes sold in fiscal 2002 attributable to unseasonably warm heating season temperatures and the economy; partially offset by (i) the $26.3 million, or 9.0%, decrease in combined operating and general and administrative expenses described above, (ii) the impact of the $6.8 million gain on the sale of our Hattiesburg, Mississippi storage facility and (iii) the impact on operating expenses of changes in the fair value of derivative instruments described above. In addition, if SFAS 142 had been in effect at the beginning of the prior year, fiscal 2001 income before interest expense and income taxes would have improved by $7.4 million. 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. Moreover, our senior note agreements and our revolving credit agreement require us to use EBITDA as a component in calculating our leverage and interest coverage ratios. EBITDA is not a recognized term under generally accepted accounting principles ("GAAP") and should not be considered as an alternative to net income or net cash provided by operating activities determined in accordance with GAAP. Because EBITDA 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 calculation of EBITDA and (ii) a reconciliation of EBITDA, as so calculated, to our net cash provided by operating activities (amounts in thousands):
Year Ended ------------------------------------------ September 28, September 29, 2002 2001 ----------------- -----------------Net income $ 53,524 $ 53,510 Add: Provision for income taxes 703 375 Interest expense, net 35,325 39,596 Depreciation and amortization 28,355 36,496 ----------------- ----------------- EBITDA 117,907 129,977 ----------------- ----------------- Add/(subtract): Provision for income taxes (703) (375) Interest expense, net (35,325) (39,596) Gain on disposal of property, plant and equipment, net (546) (3,843) Gain on sale of storage facility (6,768) - Changes in working capital and other assets and liabilities (5,790) 15,675 ----------------- ----------------- Net cash provided by/(used in) Operating activities $ 68,775 $ 101,838 ================= ================= Investing activities $ (6,851) $ (17,907) ================= ================= Financing activities $ (57,463) $ (59,082) ================= =================INTEREST INCOME AND INTEREST EXPENSE. Net interest expense decreased 10.9%, or $4.3 million, to $35.3 million in fiscal 2002 compared to $39.6 million in the prior year. This decrease is primarily attributable to reductions in average amounts outstanding during fiscal 2002 under our Revolving Credit Agreement, as well as lower average interest rates. 20LIQUIDITY AND CAPITAL RESOURCESActivities.business,and fuel oil businesses, cash flows from operating activities are greater during the winter and spring seasons, our second and third fiscal quarters, as customers pay for propane purchased during the heating season.In fiscal 2003, netNet cash provided by operating activitiesdecreased $11.5for the year ended September 24, 2005 amounted to $39.0 million, a decrease of $54.1 million, or16.7%58.1%, compared to$57.3$93.1 million infiscal 2003 compared to $68.8 million in fiscal 2002. The decrease is primarily due to lower net income, including lower non-cash items (principally depreciation, amortization and gains on asset disposals), as well astheimpact of increased investment in accounts receivable and inventories resulting from higher commodity prices and increased business activity during fiscal 2003 compared to fiscal 2002 due to generally colder average temperatures. In fiscal 2002, net cash provided by operating activities decreased $33.0 million, or 32.4%, to $68.8 million in fiscal 2002 compared to $101.8 million in fiscal 2001.prior year. The decrease wasprimarily dueattributable tolower net income, including lower non-cash items (principally depreciation, amortization and gains on asset disposals), as well as the impact of unfavorable changesa $65.3 million increased investment in working capital in comparison to the prior year,principally reflectingparticularly in increased accounts receivable balances as a result of the significant rise in commodity prices, coupled with $8.1 million lowercompensationincome, after adjusting for non-cash items in both periods (depreciation, amortization, loss on debt extinguishment andbenefit accruals,gains on disposal of assets and customer service centers); offset to an extent bylower inventories.an increase in other long-term assets and liabilities of $19.3 million. The continued high commodity price environment in both propane and fuel oil has resulted in a significant increase in average selling prices and, in turn, higher receivable balances in relation to the prior year, as well as higher average inventory costs.In fiscal 2004, net cash provided by operating activities increased $35.8 million, or 62.5%, to $93.1 million, compared to $57.3 million in fiscal 2003. The increase was primarily due to improved net income, as well as a decrease in net working capital investment compared to the prior year. Net working capital decreased primarily as a result of an increase in customer prepayments and deposits under our budget payment programs, particularly in our fuel oil and other refined fuels segment. Under these budget
payment programs, customers pay equal monthly installments beginning in June or July for the upcoming heating season based on each customer’s historical usage patterns.
Investing Activities. Net cash used in investing activities
was $4.9of $24.6 millionin fiscal 2003, reflecting $14.1 million infor the year ended September 24, 2005 consisted of capital expenditures of $29.3 million (including$4.7$10.7 million for maintenance expenditures and$9.4 million to support the growth of operations) offset by net proceeds of $9.2 million from the sale of assets (including net proceeds of $7.2 million from the sale of nine customer service centers). Net cash used in investing activities was $6.9 million in fiscal 2002, reflecting $17.5 million in capital expenditures (including $13.0 million for maintenance expenditures and $4.5 million to support the growth of operations) offset by net proceeds of $10.6 million from the sale of assets (including net proceeds of $8.0 million resulting from the sale of our propane storage facility in Hattiesburg, Mississippi). Net cash used in investing activities was $17.9 million in fiscal 2001, reflecting $23.2 million in capital expenditures (including $6.5 million for maintenance expenditures and $16.7$18.6 million to support the growth of operations), offset by net proceeds of$5.3$4.7 from the sale of property, plant and equipment. Capital spending in fiscal 2005 increased $2.8 million, or 10.6%, compared to fiscal 2004 primarily as a result of our facility integration efforts in the northeast, as well as additional spending on information technology in connection with the integration of Agway Energy.Net cash used in investing activities of $196.6 million for the year ended September 25, 2004 consisted of the net impact of the $211.2 million total cost of the Agway Acquisition partially offset by net proceeds of $39.4 million from the sale of customer service centers during fiscal 2004 and net proceeds of $1.8 million from the sale of property, plant and equipment. Additionally, capital expenditures were $26.5 million (including $7.4 million for maintenance expenditures and $19.1 million to support the growth of operations) for fiscal 2004. Capital spending in fiscal 2004 increased $12.4 million, or 87.9%, compared to fiscal 2003 primarily as a result of our facility integration efforts in the northeast, as well as additional spending on information technology in connection with the integration of Agway Energy.
Financing Activities.Net cash used in financing activities for
fiscal 2003 was $77.6the year ended September 24, 2005 of $53.4 millionreflecting (i)reflects thepaymentimpact of the March 31, 2005 debt refinancing which included the early retirement of $340.0 million of private placement senior notes and a related prepayment premium of $32.0 million, offset by net proceeds of $373.0 million, net of a discount, from the issuance of an additional $250.0 million of 6.875% senior notes due 2013 (bringing the total principal amount of such notes to $425.0 million) and borrowings of $125.0 million under ourquarterly distributions to our Common Unitholdersnew Term Loan (see Summary of Long-Term Debt Obligations andour General Partner amounting to $60.1Revolving Credit Lines below). In addition, we had borrowings of $26.8 million(ii) the repayment of all outstanding borrowingsunder our Revolving Credit Agreementamountingin order to$46.0fund increased working capital needs during the heating season, offset by $4.2 million(iii)in fees associated with closing of the March 31, 2005 debt refinancing and the Third Amended and Restated Credit Agreement in October 2004. Quarterly distributions to holders of our Common Units and the General Partner at a rate $0.6125 per Common Unit for each quarter of fiscal 2005 amounted to $76.6 million.Net cash provided by financing activities for the year ended September 25, 2004 was $141.2 million as a result of: (i) net proceeds of $169.1 million from the issuance of $175.0 million aggregate principal amount of 6.875% senior notes due 2013, a portion of which was used to fund a portion of the Agway Acquisition; and, (ii) net proceeds of $87.6 million from a public offering of approximately 3.0 million Common Units (including full exercise of the underwriters’ over-allotment option) during December 2003 to fund a portion of the Agway Acquisition; offset by: (i) the payment of a total of $72.5 million for our quarterly distributions of $0.5875 per Common Unit during each of the first two quarters of fiscal 2004, $0.60 per Common Unit during the third quarter of fiscal 2004 and $0.6125 per Common Unit during the fourth quarter of fiscal 2004; and, (ii) the repayment of the
secondthird annual principalpaymentinstallment of $42.5 million due under the 1996 Senior Note Agreement (which was terminated as a result of the Refinancing).Summary of Long-Term Debt Obligations and
(iv)Revolving Credit LinesOn October 20, 2004, our Operating Partnership executed the
payment of $0.8 millionThird Amended and Restated Credit Agreement (the ‘‘Revolving Credit Agreement’’), which replaced the Second Amended and Restated Credit Agreement then due to expire infees associated with the renewal and extension of ourMay 2006. The Revolving Credit Agreementduring May 2003. The $88.9extended the maturity to October 20, 2008 and provided available credit of $150.0 millionreductionindebt during fiscal 2003 was funded throughthe form of acombination of cash provided by operations and the net proceeds of $72.2$75.0 millionfrom a follow-on public offering of approximately 2.6 million Common Units (including full exercise of the underwriters' over-allotment option) which was completed during the third quarter of fiscal 2003. Net cash used in financing activities for fiscal 2002 was $57.5 million, primarily reflecting the payment of quarterly distributions to our Common Unitholders and our General Partner. Net cash used in financing activities for fiscal 2001 was $59.1 million, reflecting repayments under our Operating Partnership's Revolving Credit Agreement, as amended and restated effective January 29, 2001 (the "Revolving Credit Agreement"), including a net repayment of $44.0 million borrowed under the SCANA Acquisition facility and a net repayment of $6.5 million borrowed under the netrevolving working capital facility, of which $15.0 million could be used to issue letters of credit, and$54.5a separate $75.0 millionfor paymentletter ofquarterly distributions to our Common Unitholderscredit facility. The Second Amended andour General Partner, partly offset by net proceeds of $47.1 million from a public offering of approximately 2.4 million Common Units in October 2000. On March 5, 1996, pursuant to a Senior Note Agreement (the "1996 Senior Note Agreement"), we issued $425.0 million of senior notes (the "1996 Senior Notes") with an annual interest rate of 7.54%. Our obligations under the 1996 Senior Note Agreement are unsecured and rank on an equal and ratable basis with our obligations under the 2002 Senior Note Agreement and the RevolvingRestated Credit Agreementdiscussed below. Under the terms of the 1996 Senior Note Agreement, we became obligated to pay the principal on the 1996 Senior Notes in equal annual payments of $42.5 million starting July 1, 2002, with the last such payment due June 30, 2011. On July 1, 212002, we received net proceeds of $42.5 million from the issuance of 7.37% Senior Notes due June, 2012 (the "2002 Senior Notes") and used the funds to pay the first annual principal payment of $42.5 million due under the 1996 Senior Note Agreement. Our obligations under the agreement governing the 2002 Senior Notes (the "2002 Senior Note Agreement") are unsecured and rank on an equal and ratable basis with our obligations under the 1996 Senior Note Agreement and the Revolving Credit Agreement. Rather than refinance the second annual principal payment of $42.5 million due under the 1996 Senior Note Agreement, we elected to repay this principal payment on June 30, 2003. Our previous Revolving Credit Agreement, whichprovided a $75.0 million working capital facility and a$50.0$25.0 million acquisitionfacility, was scheduled to mature on May 31, 2003. On May 8, 2003, we completedfacility. In connection with theSecond Amended and Restated Credit Agreement (the "Revolving Credit Agreement") which extends the previousRevolving Credit Agreement,until Mayour permitted leverage ratio (the ratio of total debt to EBITDA) was reduced from a ratio of 5.0 to 1 to a ratio of less than 4.5 to 1.On March 31,
2006.2005, we completed a refinancing (the ‘‘Refinancing’’) of our Operating Partnership’s $297.5 million outstanding principal amount of 1996 Senior Notes due 2011 and $42.5 million outstandingprincipal amount of 2002 Senior Notes due 2012 (collectively, the ‘‘Redeemed Notes’’). Under the Refinancing, we issued $250.0 million of additional notes under the indenture governing our 2003 Senior Notes and received proceeds of approximately $246.9 million, net of a $2.0 million discount on sale and related underwriter fees. In addition, our Operating Partnership entered into the first amendment to the Revolving Credit Agreement to provide, among other things, for a five-year $125.0 million term loan facility (the ‘‘Term Loan’’). The total net proceeds of approximately $371.9 million from the issuance of additional senior notes under the indenture governing the 2003 Senior Notes and from the $125.0 million of borrowings under the Term Loan, together with cash of approximately $7.3 million, were used to prepay the Redeemed Notes, including a prepayment premium of approximately $32.0 million and interest accrued on the Redeemed Notes of approximately $6.4 million from the last interest payment date through the date of redemption.
The Redeemed Notes required an annual principal repayment of $42.5 million through 2012. The Refinancing replaced the annual cash requirement for principal amortization with the $125.0 million five-year Term Loan due 2010 and the $250.0 million of additional 2003 Senior Notes due 2013, significantly extending our debt maturities and eliminating refinancing risk associated with the amortization of the Redeemed Notes. The Refinancing is expected to reduce our annual interest expense for at least the next five years. We recorded a one-time charge of $36.2 million for the year ended September 24, 2005 as a result of the Refinancing to reflect the loss on debt extinguishment associated with the prepayment premium of $32.0 million and the write-off of $4.2 million of unamortized bond issuance costs associated with the Redeemed Notes.
As a result of the Refinancing, we eliminated our requirement under the Redeemed Notes to maintain a leverage ratio and an interest coverage ratio without adding a comparable financial covenant under the 2003 Senior Notes. As a result of the first amendment to the Revolving Credit Agreement, our Operating Partnership’s permitted leverage ratio was reduced from a ratio of 4.5 to 1 to a ratio of less than 4.0 to 1 and the interest coverage ratio (the ratio of EBITDA to interest expense) was amended to require maintenance of a ratio of greater than 2.5 to 1 on a consolidated basis. The Revolving Credit Agreement
provides aand the 2003 Senior Notes both contain various restrictive and affirmative covenants applicable to our Operating Partnership and us, 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. We were in compliance with all covenants and terms of all of our debt agreements as of September 24, 2005 and as of the end of each fiscal quarter for all periods presented.On August 26, 2005, we completed the second amendment to the Revolving Credit Agreement pursuant to which the lenders (i) eliminated the stand-alone $75.0 million letter of credit facility and combined that credit with the existing revolving working capital facility; (ii) increased the revolving working capital facility by an additional $25.0 million, thereby raising the amount of the working capital facility from $75.0 million to $175.0 million (including the $75.0 million from the former stand-alone letter of credit facility); (iii) extended the revolving credit facility’s expiration date to match the March 31, 2010 maturity date of the $125.0 million Term Loan; and,
an acquisition(iv) amended certain other terms to effect the foregoing. All other terms and conditions under the Revolving Credit Agreement remained the same. As of September 24, 2005, there was $26.8 million outstanding under the working capital facility of$25.0 million.the Revolving Credit Agreement that was used to fund working capital requirements.The 2003 Senior Notes mature on December 15, 2013, and require semi-annual interest payments that began on June 15, 2004. 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, embedded within the 2003 Senior Notes is 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
plus a margin,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.These terms are substantially the same as the terms under the previous Revolving Credit Agreement.In connection with the
completionTerm 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 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,we repaid $21.0 millionis not included in, and will be paid in addition to, this fixed interest rate ofoutstanding borrowings under the Revolving Credit Agreement. On June 19, 2003, we repaid the remaining outstanding balance of $25.0 million under the Revolving Credit Agreement. As of September 27, 2003 there were no borrowings outstanding under the Revolving Credit Agreement. As of September 28, 2002, $46.0 million was outstanding under the acquisition facility of the previous Revolving Credit Agreement and there were no borrowings under the working capital facility. The 1996 Senior Note Agreement, the 2002 Senior Note Agreement and the Revolving Credit Agreement contain various restrictive and affirmative covenants applicable to our Operating4.66%.Partnership
including (a) maintenance of certain financial tests, including, but not limited to, a leverage ratio of less than 5.0 to 1 and an interest coverage ratio in excess of 2.5 to 1 using EBITDA in such ratio calculations, (b) restrictions on the incurrence of additional indebtedness, and (c) restrictions on certain liens, investments, guarantees, loans, advances, payments, mergers, consolidations, distributions, sales of assets and other transactions. During December 2002, we amended the 1996 Senior Note Agreement to (i) eliminate an adjusted net worth financial test to be consistent with the 2002 Senior Note Agreement and Revolving Credit Agreement, and (ii) require a leverage ratio of less than 5.25 to 1 when the underfunded portion of our pension obligations is used in the computation of the ratio. We were in compliance with all covenants and terms of all of our debt agreements as of September 27, 2003 and at the end of each fiscal quarter for all periods presented.DistributionsWe will make distributions in an amount equal to all of our Available Cash, as defined in
theour Second Amended and Restated Partnership Agreement (the ‘‘Partnership Agreement’’), approximately 45 days after the end of each fiscal quarter to holders of record on the applicable record dates.TheOur Board of Supervisors reviews the level of Available Cash on a quarterly basis based upon information provided by management. Duringeach of the first three quarters offiscal2003,2005, we paid quarterly distributions to our Common Unitholders of$0.5750$0.6125 per Common Unit. OnJuly 24, 2003, the Board of Supervisors declared a $0.05 annualized increase in the quarterly distribution from $0.5750 per Common Unit to $0.5875 per Common Unit, or $2.35 on an annualized basis, for the third quarter of fiscal 2003, which was paid on August 12, 2003. OnOctober23, 2003, the20, 2005, our Board of Supervisors declared a quarterly distribution of$0.5875$0.6125 per Common Unitforin respect of the fourth quarter of fiscal2003,2005, which was paid on November10, 20038, 2005 to holders of record on November3, 2003.1, 2005.Quarterly distributions include Incentive Distribution Rights
("IDRs"(‘‘IDRs’’) payable to the General Partner to the extent the quarterly distribution exceeds $0.55 per Common Unit. The IDRs represent an incentive for the General Partner (which isownedmajority-owned byour management)senior management of the Partnership) to increase the distributions to Common Unitholders in excess ofthe$0.55 per Common Unit. With regard to the first $0.55 of the Common Unit distribution,98.29%98.46% of the Available Cash is distributed to the Common Unitholders and1.71%1.54% is distributed to the GeneralPartner 22(98.11% and 1.89%, respectively, prior to our June 2003 public offering).Partner. With regard to the balance of the Common Unit distributions paid, 85% of the Available Cash is distributed to the Common Unitholders and 15% is distributed to the General Partner.As discussed above, the results of operations for the fiscal year ended September 27, 2003 were impacted by generally colder average temperatures compared to fiscal 2002 across much of the United States, a challenging commodity pricePension Plan Assets and
supply environment and the sustained economic recession. Our results of operations were favorably impacted by a return to more normal weather patterns, particularly in the east, and our continued focus on managing our cost structure; despite the negative effects of unseasonably warm weather in the west and the economy. In addition, our product supply and risk management activities helped to ensure adequate supply and to mitigate the impact of propane price volatility during a period of uncertainty surrounding the situation in Iraq and other oil producing nations. We took several steps during fiscal 2003 to further strengthen our balance sheet and improve our leverage, highlighted by the successful completion during the third quarter of a follow-on public offering of approximately 2.6 million Common Units and the repayment of $88.9 million of debt. The lower debt levels resulted in approximately $2.0 million lower interest expense in fiscal 2003 compared to the prior year. Our anticipated cash requirements for fiscal 2004 include maintenance and growth capital expenditures of approximately $19.0 million for the repair and replacement of property, plant and equipment, approximately $30.0 million of interest payments on the 1996 Senior Notes, the 2002 Senior Notes and the Revolving Credit Agreement and a principal payment of $42.5 million due on June 30, 2004 under the 1996 Senior Note Agreement. In addition, assuming distributions remain at the current level, we will be required to pay approximately $65.8 million in distributions to Common Unitholders and the General Partner during fiscal 2004. Based on our current estimate of our cash position, availability under the Revolving Credit Agreement (unused borrowing capacity under the working capital facility of $69.5 million at September 27, 2003) and expected cash flow from operating activities, we expect to have sufficient funds to meet our current and future obligations. In connection with the pending acquisition of the assets and operations of Agway Energy, we expect to close the acquisition upon completion of the auction process, final approval of the acquisition by the Bankruptcy Court and necessary regulatory approvals. At present, we plan to fund the $206.0 million purchase price and related acquisition costs and expenses with capital markets financings. In the interim, we have obtained a commitment from established investment banking institutions to provide a $210.0 million 364-day facility to fund all or a portion of the purchase price. If we draw on this facility, it would bear interest at a floating rate and, at our option, may be converted at maturity into a 9-year term loan. If the facility were drawn, we would seek to arrange for other permanent financing to repay the facility at our earliest opportunity, possibly through one or more offerings of equity or debt securities. Following consummation of the acquisition, we believe that we will have sufficient cash flow from operating activities and availability under our Revolving Credit Agreement to fund the incremental cash requirements and to fund incremental working capital needs of the Agway Energy business for the forseeable future. PENSION PLAN ASSETSObligationsWhile our pension asset portfolio has experienced significantly improved asset returns
inover the past three fiscal2003,years, the funded status of our defined benefit pension plan continues to beimpactedaffected by the negative impact of the low interest rate environmentaffectingon the actuarial value of the projected benefit obligations, as well as the cumulative impact of prior losses particularly during fiscal 2002 and fiscal 2001.As a result, theThe projected benefit obligation as of September27, 200324, 2005 exceeded the market value of pension plan assets by$42.1$40.2 million,which improved $11.1an increase of $5.2 million compared to the$53.2$35.0 million underfunded position at the end of the prior year.The improvement in the funded status compared to fiscal 2002 has also resulted in a favorable adjustment of $5.0 million to accumulated other comprehensive (loss)/income, a component of partners' capital, at the end of fiscal 2003. Therefore, the cumulative reduction to 23partners' capital amounted to $80.1 million on the consolidated balance sheet at September 27, 2003 compared to the cumulative reduction of $85.1 million as of September 28, 2002. The cumulative reduction to partners' capital is attributable to the level of unrealized losses experienced on our pension assets over the past three years and represent non-cash charges to our partners' capital with no impact on the results of operations for the fiscal year ended September 27, 2003.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
theour benefit obligations, effective January 1, 2003, all future service credits were eliminated.For purposes of computingTherefore, eligible participants will receive interest credits only toward their ultimate defined benefit under theactuarial valuation of projecteddefined benefitobligations, we reduced the discount rate assumption from 6.75% as of September 28, 2002 to 6.0% as of September 27, 2003 to reflect an estimate of current market expectations related to long term interest rates. Additionally, we reduced the expected long-term rate of return on plan assets assumption from 8.5% as of September 28, 2002 to 7.75% as of September 27, 2003 based on the current investment mix of ourpensionasset portfolio and historical asset performance.plan. There were no minimum funding requirements for the defined benefit pension plan during fiscal2003, 20022005, 2004 or2001.2003. However, in an effort to proactively address our funded status, we elected to makeavoluntarycontribution of $10.0 millioncontributions to our defined benefit pension plan of $15.1 million and $10.0 million duringthe fourth quarter offiscal 2004 and fiscal 2003,thus improving our funded status. Thisrespectively. These voluntarycontribution,contributions, coupled with improved asset returns in our pension asset portfolio during fiscal 2005, fiscal 2004 and fiscal 2003, partially offset the negative effects on the funded status of further declines in the interest rate environment.In addition, during fiscal 2004 lump sum benefit payments to either terminated or retired individuals of $12.3 million exceeded the interest cost component of the net periodic pension cost. As a result, pursuant to SFAS 88 we recorded a non-cash settlement charge of $5.3 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.’’ As of September 24, 2005, the cumulative reduction to partners’
capital decreased to $75.7 million, compared to $76.9 million at the end of fiscal 2004, primarily as a result of continued strength in our asset portfolio returns, offset to an extent by lower benchmark interest rates. The cumulative reduction to partners’ capital is attributable to the level of unrealized losses experienced on our pension assets over the past several years and represents non-cash charges to our partners’ capital with no impact on the results of operations for the year ended September 24, 2005. Additional pension settlement charges may be required in future periods depending on the level of lump sum benefit payments.
There can be no
assurancesassurance that future declines in capital markets, or interest rates, will not have an adverse impact on our results of operations or cash flow.LONG-TERM DEBT OBLIGATIONS AND OPERATING LEASE OBLIGATIONS CONTRACTUAL OBLIGATIONSFor purposes of computing the actuarial valuation of projected benefit obligations, we reduced the discount rate assumption from 5.50% as of September 25, 2004 to 5.25% as of September 24, 2005 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 periodic pension cost for fiscal 2005, 2004 and 2003 we assumed declining long-term rates of return on plan assets of 7.50%, 7.75% and 8.50%, respectively, based on the investment mix of our pension asset portfolio, historical asset performance and expectations for future performance. There are currently no minimum funding requirements projected for fiscal 2006 and, based on information provided by our actuaries, we do not project any minimum funding requirements until fiscal 2009.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 specified 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 a settlement by increasing their accumulated benefits under the defined benefit pension plan noted above. 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
27, 200324, 2005 are due asfollows (amountsfollows:(Dollars in thousands)
:
Fiscal Fiscal Fiscal Fiscal 2008 and 2004 2005 2006 2007 thereafter Total ---------------- -------------- ------------- --------------- --------------- --------------Long-term debt $ 42,911 $ 42,940 $ 42,975 $ 42,500 $ 212,500 $ 383,826 Operating leases 17,796 12,868 9,959 5,860 6,410 52,893 Total long-term debt obligations and ---------------- -------------- ------------- --------------- --------------- -------------- lease commitments $ 60,707 $ 55,808 $ 52,934 $ 48,360 $ 218,910 $ 436,719 ================ ============== ============= =============== =============== ==============
Fiscal 2006 Fiscal 2007 Fiscal 2008 Fiscal 2009 2010 and
thereafterTotal Long-term debt $ 27,225 $ — $ — $ — $ 548,070 $ 575,295 Operating leases 20,295 15,096 10,688 5,856 5,814 57,749 Total long-term debt obligations and lease commitments $ 47,520 $ 15,096 $ 10,688 $ 5,856 $ 553,884 $ 633,044 Additionally, we have standby letters of credit in the aggregate amount of
$35.4$53.0 million, in support of retention levels under our casualty insurance programs and certain lease obligations, which expireon March 1, 2004. OFF-BALANCE SHEET ARRANGEMENTS OPERATING LEASESperiodically through October 25, 2006.Off-Balance Sheet Arrangements
Operating Leases
We lease certain property, plant and equipment for various periods under noncancelable operating leases, including
allthe majority of our railroad tank cars, approximately70%69% of our vehicle fleet, approximately30%26% of our customer service centers and portions of our information systems equipment.Rental expense under operating leases was $28.6 million, $27.3 million and $24.3 million
$24.0 millionfor fiscal years 2005, 2004 and$23.4 million for the years ended September 27,2003,September 28, 2002 and September 29, 2001,respectively. Future minimum rental commitments under noncancelable operating lease agreements as of September27, 200324, 2005 are presented in theimmediately preceding table. 24GUARANTEES Financial Accounting Standards Board ("FASB") Financial Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements fortable above.Guarantees
Including Indirect Guarantees of Indebtedness of Others," expands the existing disclosure requirements for guarantees and requires recognition of a liability for the fair value of guarantees issued after December 31, 2002.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
2009.2012. 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$14.4$18.1 million. Of this amount, the fair value of residual value guarantees for operating leases entered into after December 31, 2002was $2.1 million whichis reflected in other liabilities, with a corresponding amount included within other assets in the accompanying consolidated balance sheet totaling $6.3 million and $3.7 million as of September27, 2003. RECENTLY ISSUED ACCOUNTING STANDARDS24, 2005 and September 25, 2004, respectively.Recently Issued Accounting Standards
In
June 2002,March 2005, the Financial Accounting Standards Board (‘‘FASB’’) issued FASBissued SFASInterpretation No.146, "Accounting47, ‘‘Accounting forCosts Associated with Exit or Disposal Activities" ("SFAS 146"Conditional Asset Retirement Obligations’’ (‘‘FIN 47’’).SFAS 146FIN 47 clarifies the term conditional asset retirement obligation as a legal obligation to retire an asset when the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. FIN 47 also requirescompaniesan entity to recognizecosts associateda liability for the fair value of the conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. FIN 47 is effective beginning withexit or disposal activities when they are incurred rather than atthedate of a commitment to an exit or disposal plan.Partnership’s fiscal year ending September 30, 2006. Theprovisions of SFAS 146 are effective for exit or disposal activities initiated after December 31, 2002. We will applyPartnership is currently evaluating the provisions ofthis standard on an ongoing basis, as applicable. In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative InstrumentsFIN 47 andHedging Activities" ("SFAS 149"). SFAS 149 amends SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. This statement is, in general, effective for contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003. Thecurrently believes that adoptionof this standard didwill not have a materialimpacteffect onour consolidatedits financial position, results of operations or cash flows.In
May 2003,December 2004, the FASB issued a revised SFAS No.150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" ("123, ‘‘Share-Based Payment’’ (‘‘SFAS150"123R’’). SFAS150 establishes standards123R is a revision of SFAS No. 123 ‘‘Accounting for Stock-Based Compensation’’ and supersedes APB Opinion No. 25 ‘‘Accounting for Stock Issued to Employees’’. SFAS 123R requires a public entity to measure theclassificationcost of employee services received in exchange for an award of equity instruments based on the grant date fair value of the award. SFAS 123R eliminates the alternative of using the APB Opinion No. 25 intrinsic value method of accounting that was provided for in SFAS No. 123 as originally issued andmeasurement of certain financial instruments with characteristics of both liabilities and equity. Itrequires thatan issuer classify athe compensation cost relating to share-based payment transactions be recognized in the financialinstrument that is within its scope as a liability (or an asset in some circumstances). Many of these instruments were previously required to be classified as equity. This statementstatements. SFAS 123R is effectivefor financialbeginning with the Partnership’s fiscal year ending September 30, 2006. The Partnership has historically recognized unearned compensation associated with awards of equity instrumentsentered into or modified after May 31, 2003, and otherwise is effective for our fourth quarter in fiscal 2003. Theratably to expense over the vesting period (see Note 10). Accordingly, adoption ofthis standard didSFAS 123R is not expected to havea materialan impact onourthe Partnership’s consolidated financial position, results ofoperationsoperation or cash flows.In January 2003, the FASB issued FASB Interpretation No. 46, "Consolidation of Variable Interest Entities" ("FIN 46"), an interpretation of Accounting Research Bulletin No. 51, "Consolidated Financial Statements." FIN 46 addresses consolidation by business enterprises of variable interest entities that meet certain characteristics. The consolidation requirements of FIN 46 apply immediately to variable interest entities created after January 31, 2003. The consolidation requirements apply to variable interest entities created before February 1, 2003 in the first fiscal year or interim period 25beginning after June 15, 2003. However, in October 2003, the FASB deferred the effective date for applying certain provisions of FIN 46 and in November 2003, issued an exposure draft which would amend certain provisions of FIN 46. As a result of the latest exposure draft, we are currently evaluating the impact, if any, that FIN 46 or any future amendment may have on our financial position and results of operations. 26ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK As of September
27, 2003,24, 2005, we were a party topropane forwardexchange-traded futures and option contracts, forward contracts and in certain instances, over-the-counter options (collectively ‘‘derivative instruments’’) to manage the price risk associated withvarious third partiesfuture purchases of the commodities used in our operations, principally propane andfutures traded on the New York Mercantile Exchange (the "NYMEX").fuel oil. Futures and forward contracts require that we sell or acquire propane or fuel oil at a fixed price 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; 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 ofpropanethe product to the respective party or are settled by the payment of a net amount equal to the difference between the then current priceof propaneand the fixed contract price. The contracts are entered into in anticipation of market movements and to manage and hedge exposure to fluctuating prices of propaneprices,and fuel oil, as well as to help ensure the availability ofpropaneproduct during periods of high demand.Market
risks associated with the trading of futures, options and forward contracts are monitored daily for compliance with our trading policy which includes volume limits for open positions. Open inventory positions are reviewed and managed daily as to exposures to changing market prices. MARKET RISKRiskWe 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
onof 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.CREDIT RISKMarket 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.
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIESInterest 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 new 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 24, 2005, the fair value of the interest rate swap was $1.3 million and was included within other liabilities.
Derivative Instruments and Hedging Activities
We account for derivative instruments in accordance with the provisions of SFAS No. 133,
"Accounting‘‘Accounting for Derivative Instruments and Hedging Activities,"’’ as amended by SFAS No. 137, SFAS No. 138 and SFAS No.149.149 (‘‘SFAS 133’’). All derivative instruments are reported on the balance sheet, within other current assets or other current liabilities, at their fair values. Fair values for forward contracts and futures are derived from quoted market prices for similar instruments traded on the NYMEX. 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.Prior to March 31, 2002, we determined that ourChanges in the fair value of derivative instrumentsdid not qualifyare recorded each period in current period earnings or OCI, depending on whether a derivative instrument is designated ashedgesa hedge and,as such,if it is, thechanges in fair values were recorded in income. Beginning with contracts entered into subsequent to March 31, 2002, a portiontype ofthe derivative instruments entered into have been designated and qualify as cash flow hedges.hedge. For derivative instrumentsdesignated as cash flow hedges, we formally assess, both at the hedge
contract'scontract’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 inaccumulated other comprehensive (loss)/income ("OCI")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 hedges are recognized in cost of products sold immediately.Changes in the fair value of derivative instruments that are not designated as hedges are recorded in current period
earnings. Fair values for forwardearnings within operating expenses. A portion of our option contracts are not classified as hedges and,futuresas such, changes in the fair value of these derivative instruments arederived from quoted market prices for similar instruments traded onrecognized within operating expenses as they occur. The value of certain option contracts that do qualify as hedges and are designated as cash flow hedges under SFAS 133 have two components of value: time value and intrinsic value. The intrinsic value is theNYMEX. 27value by which the option is in the money (i.e., the amount by which the value of the commodity exceeds the exercise or ‘‘strike’’ price of the option). The remaining amount of option value is attributable to time value. We do not include the time value of option contracts in our assessment of hedge effectiveness and, therefore, record changes in the time value component of the options currently in earnings. At September
27, 2003,24, 2005, the fair value of derivative instruments described above resulted in derivative assets of $0.6 million included within prepaid expenses and other current assets and derivative liabilities of$1.7$7.9 million included within other current liabilities. For the year ended September27, 200324, 2005 operating expenses include unrealized (non-cash) losses of$1.5$2.5 million compared to unrealized (non-cash)gainslosses of$5.4$4.5 million for the year ended September28, 2002,25, 2004, attributable to the change in the fair value of derivative instruments not designated as hedges.AtAs of September27, 2003,24, 2005, there were no unrealized gainson derivative instruments designated as cash flow hedges in the amount of $1.1 million wereor losses attributable to commodity hedging transaction includedin OCI and are expected to be recognized in earnings during the next 12 months as the hedged 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. SENSITIVITY ANALYSISwithin OCI.Sensitivity 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:
A. The actual fixed contract price of open positions as of September 27, 2003 for each of the future periods. B. The estimated future market prices for futures and forward contracts as of September 27, 2003 as derived from the NYMEX for traded propane futures for each of the future periods. C. The market prices determined in B. above were adjusted adversely by a hypothetical 10% change in the future periods and compared to the fixed contract settlement amounts in A. above to project the potential negative impact on earnings that would be recognized for the respective scenario.
A. The actual fixed contract price of open positions as of September 24, 2005 for each of the future periods.
B. The estimated future market prices for futures and forward contracts as of September 24, 2005 as derived from the NYMEX for traded propane or fuel oil futures for each of the future periods.
C. The market prices determined in B. above were adjusted adversely by a hypothetical 10% change in the future periods and compared to the fixed contract settlement amounts in A. above to project the potential negative impact on earnings that would be recognized for the respective scenario. Based on the sensitivity analysis described above, the hypothetical 10% adverse change in market prices for each of the future months for which a future, forward and/or option contract exists indicate
eithera reduction in potential future gainsor potential losses in future earningsof$3.3 million and $0.7$3.0 million as of September27, 2003 and September 28, 2002, respectively.24, 2005. 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.As of September 27, 2003, our open position portfolio reflected a net long position (purchase) aggregating $19.2 million.The average posted price of propane onNovember 21, 2003September 24, 2005 at Mont Belvieu, Texas (a major storage point) was55.63 cents$1.1638 per gallon as compared to50.75 cents$0.8225 per gallon on September27, 2003, representing25, 2004. The average posted price of fuel oil on September 24, 2005 at Linden, New Jersey was $1.909 per gallon as compared to $1.36 per gallon on September 25, 2004. Since the end of fiscal 2005, both propane and fuel oil average posted prices have declined approximately 15% to $0.9788 per gallon and $1.614 per gallon, respectively, on November 28, 2005.As of September 24, 2005, our open position portfolio reflected a
9.6% increase. 28net short position (sell contracts) aggregating $22.3 million.ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Our Consolidated Financial Statements and the Report of Independent
AuditorsRegistered Public Accounting Firm thereon and the Supplemental Financial Information listed on the accompanying Index to Financial Statement Schedule are included herein.SELECTED QUARTERLY FINANCIAL DATASelected 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).
First
QuarterSecond
QuarterThird
QuarterFourth
QuarterTotal
YearFiscal 2005 Revenues $ 424,046 $ 587,369 $ 327,180 $ 281,639 $ 1,620,234 Income (loss) before interest expense, loss on debt extinguishment and provision for income taxes (a) 34,853 75,070 (13,589 ) (27,967 ) 68,367 Income (loss) from continuing operations (a) 24,901 64,481 (59,912 ) (38,522 ) (9,052 ) Discontinued operations: Gain on sale of customer service centers (b) — 976 — — 976 Net income (loss) (a) 24,901 65,457 (59,912 ) (38,522 ) (8,076 ) Income (loss) from continuing operations per common
unit – basic0.77 1.89 (1.92 ) (1.23 ) (0.29 ) Net income (loss) per common unit – basic (c) 0.77 1.91 (1.92 ) (1.23 ) (0.26 ) Net income (loss) per common unit – diluted (c) 0.77 1.90 (1.92 ) (1.23 ) (0.26 ) Cash provided by (used in) Operating activities (29,627 ) 7,531 44,383 16,718 39,005 Investing activities (7,909 ) (5,035 ) (6,182 ) (5,505 ) (24,631 ) Financing activities (96 ) (1,443 ) (43,895 ) (8,010 ) (53,444 ) EBITDA (e) $ 43,972 $ 85,244 $ (4,393 ) $ (17,718 ) $ 107,105 Retail gallons sold Propane 141,780 199,124 98,008 77,128 516,040 Fuel oil and refined fuels 65,906 92,886 48,468 37,276 244,536 Fiscal 2004 (d) Revenues $ 215,572 $ 567,324 $ 279,694 $ 244,664 $ 1,307,254 Income (loss) before interest expense and income taxes (a) 29,972 88,518 (14,057 ) (34,654 ) 69,779 Income (loss) from continuing operations (a) 20,178 77,665 (24,321 ) (44,578 ) 28,944 Discontinued operations: Gain on sale of customer service centers (b) — 14,205 619 11,508 26,332 (Loss) income from discontinued customer service centers (87 ) 690 (635 ) (940 ) (972 ) Net income (loss) (a) 20,091 92,560 (24,337 ) (34,010 ) 54,304 Income (loss) from continuing operations per common
unit – basic0.70 2.26 (0.78 ) (1.43 ) 0.96 Net income (loss) per common unit – basic (c) 0.70 2.68 (0.78 ) (1.09 ) 1.79 Net income (loss) per common unit – diluted (c) 0.70 2.67 (0.78 ) (1.09 ) 1.78 Cash provided by (used in) Operating activities 11,561 11,773 77,902 (8,171 ) 93,065 Investing activities (214,995 ) 15,355 (4,464 ) 7,547 (196,557 ) Financing activities 240,315 (18,348 ) (19,093 ) (61,666 ) 141,208 EBITDA (e) $ 37,114 $ 112,636 $ (4,896 ) $ (12,972 ) $ 131,882 Retail gallons sold Propane 131,917 219,945 99,492 85,976 537,330 Fuel oil and refined fuels 8,058 104,157 60,298 47,956 220,469
First Second Third Fourth Total Quarter Quarter Quarter Quarter Year -------------- --------------- --------------- --------------- --------------- Fiscal 2003 - -----------Revenues $ 204,469 $ 295,435 $ 146,171 $ 125,604 $ 771,679 Income/(loss) before interest expense(a) These amounts include, in addition to the gain on sale of customer service centers, gains from the disposal of property, plant and income taxes (a) 32,240 64,815 (3,598) (13,440) 80,017 Income/(loss) from continuing operations (a) 23,254 55,902 (12,014) (20,956) 46,186 Discontinued operations:equipment of $2.0 million for fiscal 2005 and $0.7 million for fiscal 2004.
(b) Gain on sale of customer service centers (b) - 2,404 79 - 2,483 Net income/(loss) (a) 23,254 58,306 (11,935) (20,956) 48,669 Income/(loss) from continuing operations per common unit - basic 0.92 2.21 (0.47) (0.75) 1.78 Net income/(loss) per common unit - basic (c) 0.92 2.31 (0.47) (0.75) 1.87 Net income/(loss) per common unit - diluted (c) 0.92 2.30 (0.47) (0.75) 1.86 Cash provided by/(used in): Operating activities 8,378 14,988 45,557 (11,623) 57,300 Investing activities (2,561) 3,235 (1,205) (4,328) (4,859) Financing activities (14,591) (14,533) 10,655 (59,162) (77,631) EBITDA (d) $ 39,213 $ 74,019 $ 3,198 $ (6,410) $ 110,020 Retail gallonsrecorded in the second quarter of fiscal 2005 reflects a $1.0 million finalization of certain purchase price adjustments with the buyer of the customer service centers sold139,934 182,956 89,600 78,961 491,451 Fiscal 2002 - ----------- Revenues $ 181,864 $ 235,887 $ 137,635 $ 109,719 $ 665,105 Gain on sale of storage facility - 6,768 - - 6,768 Income/(loss) before interest expense and income taxes (a) 29,805 71,071 (2,499) (8,825) 89,552 Net income/(loss) (a) 20,613 61,901 (11,028) (17,962) 53,524 Net income/(loss) per common unit - basic (c) 0.82 2.46 (0.44) (0.71) 2.12 Net income/(loss) per common unit - diluted (c) 0.82 2.45 (0.44) (0.71) 2.12 Cash provided by/(used in): Operating activities 3,421 32,701 29,906 2,747 68,775 Investing activities (4,018) 4,034 (3,213) (3,654) (6,851) Financing activities (14,168) (14,168) (14,186) (14,941) (57,463) EBITDA (d) $ 37,061 $ 78,146 $ 4,549 $ (1,849) $ 117,907 Retail gallons sold 123,958 168,621 86,730 76,679 455,988(a) These amounts include, in addition to the gain on sale of customer service centers and the gain on sale of storage facility, gains from the disposal of property, plant and equipment of $0.6 million for fiscal 2003 and $0.5 million for fiscal 2002. 29(b) Gain on sale of customer service centers consists of five customer service centers we sold during the second quarter of fiscal 2003 for total cash proceeds of approximately $5.6 million and four customer service centers we sold during the third quarter of fiscal 2003 for total cash proceeds of approximately $1.6 million. We recorded a gain on sale in the second and third quarters of approximately $2.4 million and $0.1 million, respectively, which have been accounted for within discontinued operations pursuant to SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." Prior period results of operations attributable to these nine customer service centers were not significant and, as such, prior period results have not been reclassified to remove financial results from continuing operations. (c) Basic net income per Common Unit is computed by dividing net income, 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, after deducting our general partner's approximate 2% interest, by the weighted average number of outstanding Common Units and time vested restricted units granted under our 2000 Restricted Unit Plan. (d) EBITDA represents net income/(loss) 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. Moreover, our senior note agreements and our revolving credit agreement require us to use EBITDA as a component in calculating our leverage and interest coverage ratios. EBITDA is not a recognized term under generally accepted accounting principles ("GAAP") and should not be considered as an alternative to net income/(loss) 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/(loss), it may not be comparable to EBITDA or similarly titled measures used by other companies. The following table sets forth (i) our calculation of EBITDA and (ii) a reconciliation of EBITDA, as so calculated, to our net cash provided by operating activities (amounts in thousands):
First Second Third Fourth Total Quarter Quarter Quarter Quarter Year -------------- --------------- --------------- --------------- --------------- Fiscal 2003 - -----------Net income / (loss) $ 23,254 $ 58,306 $ (11,935) $ (20,956) $ 48,669 Add: Provision / (benefit) for income taxes 130 37 (64) 99 202 Interest expense, net 8,856 8,876 8,480 7,417 33,629 Depreciation and amortization 6,973 6,800 6,717 7,030 27,520 ---------------- --------------- ---------------- --------------- ---------------- EBITDA 39,213 74,019 3,198 (6,410) 110,020 ---------------- --------------- ---------------- --------------- ---------------- Add / (subtract): (Provision) / benefit for income taxes (130) (37) 64 (99) (202) Interest expense, net (8,856) (8,876) (8,480) (7,417) (33,629) Gain on disposal of property, plant and equipment, net (346) 26 (166) (150) (636)in fiscal 2004. Gain on sale of customer service centers- (2,404) (79) - (2,483) Changesfor fiscal 2004 reflects the sale of ten customer service centers during the second quarter for net cash proceeds of approximately $22.9 million, one customer service center we sold during the third quarter for net cash proceeds of approximately $0.9 million and 13 customer service centers we sold during the fourth quarter for net cash proceeds of approximately $15.6 million. We recorded a gain on sale inworking capitalthe second, third and fourth quarters of fiscal 2004 of approximately $14.1 million, $0.6 million and $11.6 million, respectively. Gains on sale of assets have been accounted for within discontinued operations pursuant to SFAS 144.
(c) Basic net income (loss) per Common Unit 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, after deducting our general partner's approximate 3.1% interest, by the weighted average number of outstanding Common Units and time vested restricted units granted under our 2000 Restricted Unit Plan. On March 31, 2004, the Emerging Issues Task Force (‘‘EITF’’) reached a consensus under EITF 03-6 ‘‘Participating Securities and the Two-Class Method Under FAS 128’’ (‘‘EITF 03-6’’) which 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 participation rights in undistributed earnings, as if all of the earnings were distributed to the limited partners and the general partner (inclusive of the IDRs which are considered participating securities for purposes of the application of EITF 03-6). We adopted EITF 03-6 at the end of fiscal 2004; however, the application of its consensus on the computation of our net income per Common Unit for the years ended September 24, 2005 or September 25, 2004 did not have any impact on annual net income per Common Unit. The requirements of EITF 03-6 do not apply to the computation of net income per Common Unit in periods in which a net loss is reported. Net income and income from continuing operations per Common Unit presented in this table for the first and second quarters of fiscal 2005 and 2004 reflect the impact of the application of EITF 03-6.
(d) Includes the results from our acquisition of substantially all of the assets and liabilities (21,503) (47,740) 51,020 2,453 (15,770) ---------------- --------------- ---------------- --------------- ---------------- Netof Agway Energy from December 23, 2003, the date of acquisition.
(e) EBITDA represents net income/(loss) before deducting interest expense, loss on debt extinguishment, 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. 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/(loss) or net cash provided by/(used in) Operatingoperating activities$ 8,378 $ 14,988 $ 45,557 $ (11,623) $ 57,300 ================ =============== ================ =============== ================ Investing activities $ (2,561) $ 3,235 $ (1,205) $ (4,328) $ (4,859) ================ =============== ================ =============== ================ Financing activities $ (14,591) $ (14,533) $ 10,655 $ (59,162) $ (77,631) ================ =============== ================ =============== ================30
First Second Third Fourth Total Quarter Quarter Quarter Quarter Year -------------- --------------- --------------- --------------- --------------- Fiscal 2002 - -----------Net income / (loss) $ 20,613 $ 61,901 $ (11,028) $ (17,962) $ 53,524 Add: Provision for income taxes 138 190 190 185 703 Interest expense,determined in accordance with GAAP. Because EBITDA as determined by us excludes some, but not all, items that affect net9,054 8,980 8,339 8,952 35,325 Depreciationincome/(loss), it may not be comparable to EBITDA or similarly titled measures used by other companies. The following table sets forth (i) our calculation of EBITDA andamortization 7,256 7,075 7,048 6,976 28,355 ---------------- --------------- ---------------- --------------- ----------------(ii) a reconciliation of EBITDA,37,061 78,146 4,549 (1,849) 117,907 ---------------- --------------- ---------------- --------------- ---------------- Add / (subtract): Provision for income taxes (138) (190) (190) (185) (703) Interest expense,as so calculated, to our net(9,054) (8,980) (8,339) (8,952) (35,325) Gain on disposal of property, plant and equipment, net (13) (263) 63 (333) (546) Gain on sale of storage facility - (6,768) - - (6,768) Changes in working capital and other assets and liabilities (24,435) (29,244) 33,823 14,066 (5,790) ---------------- --------------- ---------------- --------------- ---------------- Netcash provided by/(used in)Operatingoperating activities$ 3,421 $ 32,701 $ 29,906 $ 2,747 $ 68,775 ================ =============== ================ =============== ================ Investing activities $ (4,018) $ 4,034 $ (3,213) $ (3,654) $ (6,851) ================ =============== ================ =============== ================ Financing activities $ (14,168) $ (14,168) $ (14,186) $ (14,941) $ (57,463) ================ =============== ================ =============== ================(amounts in thousands):31ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
Fiscal 2005 First
QuarterSecond
QuarterThird
QuarterFourth
QuarterTotal
YearNet income (loss) $ 24,901 $ 65,457 $ (59,912 ) $ (38,522 ) $ (8,076 ) Add: Provision for income taxes 89 109 138 467 803 Loss on debt extinguishment — — 36,242 — 36,242 Interest expense, net 9,863 10,480 9,943 10,088 40,374 Depreciation and amortization 9,119 9,198 9,196 10,249 37,762 EBITDA 43,972 85,244 (4,393 ) (17,718 ) 107,105 Add (subtract): Provision for income taxes (89 ) (109 ) (138 ) (467 ) (803 ) Loss on debt extinguishment — — (36,242 ) — (36,242 ) Interest expense, net (9,863 ) (10,480 ) (9,943 ) (10,088 ) (40,374 ) Gain on disposal of property, plant and equipment, net (207 ) (860 ) (821 ) (155 ) (2,043 ) Gain on sale of customer service centers — (976 ) — — (976 ) Changes in working capital and other assets and liabilities (63,440 ) (65,288 ) 95,920 45,146 12,338 Net cash provided by (used in) Operating activities $ (29,627 ) $ 7,531 $ 44,383 $ 16,718 $ 39,005 Investing activities $ (7,909 ) $ (5,035 ) $ (6,182 ) $ (5,505 ) $ (24,631 ) Financing activities $ (96 ) $ (1,443 ) $ (43,895 ) $ (8,010 ) $ (53,444 )
Fiscal 2004 First
QuarterSecond
QuarterThird
QuarterFourth
QuarterTotal
YearNet income (loss) $ 20,091 $ 92,560 $ (24,337 ) $ (34,010 ) $ 54,304 Add: Provision (benefit) for income taxes 83 83 (283 ) 120 3 Interest expense, net 9,711 10,770 10,547 9,804 40,832 Depreciation and amortization 7,229 9,223 9,177 11,114 36,743 EBITDA 37,114 112,636 (4,896 ) (12,972 ) 131,882 Add (subtract): (Provision) benefit for income taxes (83 ) (83 ) 283 (120 ) (3 ) Interest expense, net (9,711 ) (10,770 ) (10,547 ) (9,804 ) (40,832 ) (Gain) loss on disposal of property, plant and
equipment, net(82 ) (79 ) 8 (562 ) (715 ) Gain on sale of customer service centers — (14,205 ) (619 ) (11,508 ) (26,332 ) Changes in working capital and other assets and liabilities (15,677 ) (75,726 ) 93,673 26,795 29,065 Net cash provided by (used in) Operating activities $ 11,561 $ 11,773 $ 77,902 $ (8,171 ) $ 93,065 Investing activities $ (214,995 ) $ 15,355 $ (4,464 ) $ 7,547 $ (196,557 ) Financing activities $ 240,315 $ (18,348 ) $ (19,093 ) $ (61,666 ) $ 141,208
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None.
ITEM 9A. CONTROLS AND PROCEDURES DISCLOSURE CONTROLS AND
PROCEDURES Our management, including our principal executive officer and principal financial officer, have evaluated the effectiveness of our "disclosurePROCEDURES. The Partnership maintains disclosure controls andprocedures"procedures (as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934)asthat are designed to provide reasonable assurance that information required to be disclosed in the Partnership’s filings under the Securities Exchange Act ofSeptember 27, 2003. Based on1934 is recorded, processed, summarized and reported within the periods specified in the rules and forms of the SEC and that suchevaluation, ourinformation is accumulated and communicated to the Partnership’s management, including its principal executive officer and principal financial officer,have concluded thatas appropriate, to allow timely decisions regarding required disclosure.On December 1, 2005, before filing this Annual Report, the Partnership completed an evaluation under the supervision and with the participation of
September 27, 2003, suchthe 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 proceduresareas of September 24, 2005. Based on this evaluation, the Partnership’s principal executive officer and principal financial officer concluded that the Partnership’s disclosure controls and procedures were effectiveforat thepurposereasonable assurance level as ofensuring that materialSeptember 24, 2005.CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING. Due to the deployment of various initiatives, including the implementation of new information
requiredtechnology systems during fiscal 2005, we modified many of our internal controls over financial reporting during the quarter ended September 24, 2005. This modification of internal control over financial reporting was made tobe in this Annual Report is made knownalign our internal controls with the implementation of our new technology initiatives, principally related tothem by others on a timely basis.our natural gas and electricity segment. Management continues to monitor these changes, as well as conducting an ongoing process of reviewing and evaluating our internal control over financial reporting.There have
notbeenanyno other changes in our internal control over financial reporting (as defined in Rule13a-15(f)13(a)–15(f) of the Securities Exchange Act of 1934) during the quarterendingended September27, 200324, 2005, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.32Management’s Report on Internal Control over Financial Reporting is included below.MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING. Management of the Partnership is responsible for establishing and maintaining adequate internal control over financial reporting. The Partnership's internal control over financial reporting is designed to provide reasonable assurance as to the reliability of the Partnership's financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
The Partnership’s management has assessed the effectiveness of the Partnership’s internal control over financial reporting as of September 24, 2005. 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 of the design and operating effectiveness of its internal control over financial reporting.
Based on the Partnership’s assessment, as described above, management has concluded that, as of September 24, 2005, the Partnership’s internal control over financial reporting was effective.
Management’s assessment of the effectiveness of the Partnership's internal control over financial reporting as of September 24, 2005 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.
ITEM 9B. OTHER INFORMATION None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
PARTNERSHIP MANAGEMENT Our Second AmendedThe information to be included under the caption ‘‘Election of Supervisors’’ and
Restated Partnership Agreement (the "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‘‘Information Concerning the Boardof Supervisors, our officers. No Unitholder has any management power over our businessandaffairs or actual or apparent authorityBoard Committees’’ in the Partnership's definitive proxy statement toenter into contracts on behalf of, or to otherwise bind, us. Three independent Elected Supervisors and two Appointed Supervisors serve onbe filed with theBoard of SupervisorsSEC pursuant tothe terms of the Partnership Agreement. The Elected Supervisors are voted on by the Unitholders to serve a term of three years. The Appointed Supervisors are appointed by our General Partner. The three Elected Supervisors serve on the Audit Committee with the authority to review, at the request of the Board of Supervisors, specific matters as to which the Board of Supervisors believes there may be a conflict of interest in order to determine if the resolution of such conflict proposed by the Board of Supervisors is fair and reasonable to us. Under the Partnership Agreement, any matters approved by the Audit Committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our General Partner or the Board of Supervisors of any duties they may owe us or the Unitholders. The primary function of the Audit Committee is to assist the Board of Supervisors in fulfilling its oversight responsibilities relating to the establishment of accounting policies; preparation of financial statements; integrity of financial reporting; compliance with applicable laws, regulations and policies; independence and performance of the internal auditor and independent accountants and findings of both the internal auditor and independent accountants. The Board of Supervisors has determined that all three members of the Audit Committee, John Hoyt Stookey, Harold R. Logan, Jr. and Dudley C. Mecum, are audit committee financial experts and are independent of management, as defined in Item 7(d)(3)(iv) of Schedule 14A. 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 21, 2003. Officers are elected for one-year terms and Supervisors are elected or appointed for three-year terms.
Position With the Name Age Partnership - ---------------------------------------- ----- ---------------------------------------------------------Mark A. Alexander....................... 45 President and Chief Executive Officer; Member of the Board of Supervisors (Appointed Supervisor) Michael J. Dunn, Jr..................... 54 Senior Vice President - Corporate Development; Member of the Board of Supervisors (Appointed Supervisor) David R. Eastin......................... 45 Senior Vice President and Chief Operating Officer Robert M. Plante........................ 55 Vice President and Chief Financial Officer Jeffrey S. Jolly........................ 51 Vice President and Chief Information Officer Michael M. Keating...................... 50 Vice President - Human Resources and Administration Janice G. Meola......................... 37 Vice President, General Counsel and Secretary A. Davin D'Ambrosio..................... 39 Treasurer Michael A. Stivala...................... 34 Controller John Hoyt Stookey....................... 73 Member of the Board of Supervisors (Chairman and Elected Supervisor) Harold R. Logan, Jr..................... 59 Member of the Board of Supervisors (Elected Supervisor) Dudley C. Mecum......................... 68 Member of the Board of Supervisors (Elected Supervisor) Mark J. Anton........................... 77 Supervisor Emeritus33Mr. Alexander has served as President and Chief Executive Officer since October 1996 and as an Appointed Supervisor since March 1996. He was Executive Vice Chairman and Chief Executive Officer from March 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), most recently Senior Vice President - Corporate Department. Mr. Alexander serves as Chairman of the Board of Managers of the General Partner. He is a member of the Executive Committee of the National Propane Gas Association. Mr. Dunn has served as Senior Vice President since June 1998 and became Senior Vice President - Corporate Development in November 2002. Mr. Dunn has served as an Appointed Supervisor since July 1998. He was Vice President - Procurement and Logistics from March 1997 until June 1998. From 1983 until joining the Partnership, Mr. Dunn was Vice President of Commodity Trading for the investment banking firm of Goldman Sachs & Company. Mr. Dunn serves on the Board of Managers of the General Partner. Mr. Eastin has served as Chief Operating Officer since May 1999 and became a Senior Vice President in November 2000. From 1992 until joining the Partnership, Mr. Eastin held various executive positions with Star Gas Propane LP, most recently as Vice President - Operations. Mr. Eastin serves on the Board of Managers of the General Partner. Mr. Plante has served as a Vice President since October 1999 and became Vice President and Chief Financial Officer in November 2003. He was Vice President - Finance from March 2001 until November 2003 and Treasurer from March 1996 through October 2002. Mr. Plante held various financial and managerial positions with predecessors of the Partnership from 1977 until 1996. Mr. Jolly has served as Vice President and Chief Information Officer since May 1999. He was Vice President - Information Services from July 1997 until May 1999. From May 1993 until joining the Partnership, Mr. Jolly was Vice President - - Information Systems at The Wood Company, a food services company. 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. D'Ambrosio became Treasurer in November 2002. He served as Assistant Treasurer from October 2000 to November 2002 and as Director of Treasury Services from January 1998 to October 2000. Mr. D'Ambrosio joined the Partnership in May 1996 after ten years in the commercial banking industry. Ms. Meola has served as Vice President, General Counsel and Secretary since November 2003. From May 1999 until November 2003, Ms. Meola served as General Counsel and Secretary. She was Counsel from July 1998 to May 1999 and Associate Counsel from September 1996, when she joined the Partnership, until July 1998. Mr. Stivala has served as Controller since December 2001. From 1991 until joining the Partnership, he held several positions with PricewaterhouseCoopers LLP, 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. Stookey has served as an Elected Supervisor and Chairman of the Board of Supervisors since March 1996. From 1986 until September 1993, he was the Chairman, President and Chief Executive Officer of Quantum and 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. 34Mr. Logan has served as an Elected Supervisor since March 1996. He is a Director and Chairman of the Finance Committee of the Board of Directors of TransMontaigne Inc., which provides 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 The Houston Exploration Company, Graphic Packaging, Inc. and Rivington Capital Advisors, LLC. Mr. Mecum has served as an Elected 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. Mecum is a director of Lyondell, Dyncorp, CitiGroup and Mrs. Fields Famous Brands, Inc. Mr. Anton has served as Supervisor Emeritus of the Board of Supervisors since January 1999. He is a former President, Chief Executive Officer and Chairman of the Board of Directors of Suburban Propane Gas Corporation, a predecessor of the Partnership, and a former Executive Vice President of Quantum. BENEFICIAL OWNERSHIP REPORTING COMPLIANCE Section 16(a)Regulation 14A of the Exchange Actrequires our directors and executive officers to file initial reports of ownership and reports of changesinownership of our Common Unitsconnection with theSecurities and Exchange Commission. Directors, executive officers and ten percent2006 tri-annual meeting of Common Unitholdersare required to furnishof the Partnershipwith copies of all Section 16(a) forms that they file. Based on a review of these filings, we believe that all such filings were made timely during fiscal 2003. CODE OF ETHICS We have adopted a code of ethics that applies to our senior executive team, including our principal executive officer, principal financial officer and principal accounting officer. Copies of our code of ethics 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 this code of ethics that apply to our principal executive officer, principal financial officer and principal accounting officer will be posted on our website. 35(the ‘‘Proxy Statement’’) is incorporated herein by reference. ITEM 11. EXECUTIVE COMPENSATION
SUMMARY COMPENSATION TABLEThe
following table sets forth a summary of all compensation awarded or paidinformation toor earned by our chief executive officer and our four other most highly compensated executive officers for services rendered to us during each of the last three fiscal years.
Annual Compensation -------------------------- LTIP All Other Name and Principal Position Year Salary Bonus(1) Payout Compensation(2) - --------------------------- ---- ---------- -------- ------- ---------------Mark A. Alexander 2003 $450,000 $192,150 - $167,037 President and Chief Executive Officer 2002 450,000 157,500 25,382 158,513 2001 450,000 450,000 7,141 166,371 Michael J. Dunn, Jr. 2003 280,000 101,626 27,403 95,695 Sr. Vice President - Corporate Development 2002 275,000 81,813 12,135 85,956 2001 260,000 221,000 3,414 89,321 David R. Eastin 2003 265,000 96,182 - 91,721 Senior Vice President and 2002 260,000 77,350 2,018 81,984 Chief Operating Officer 2001 240,000 204,000 - 84,362 Robert M. Plante 2003 180,000 46,116 - 39,038 Vice President and Chief Financial Officer 2002 175,000 45,625 3,807 32,938 2001 150,000 75,000 1,071 35,169 Jeffrey S. Jolly 2003 182,500 38,964 10,366 50,443 Vice President and Chief Information Officer 2002 177,500 31,063 4,600 41,414 2001 170,000 85,000 1,294 47,660(1) Bonuses are reported for the year earned, regardless of the year paid. (2) For Mr. Alexander, this amount includes the following: $3,000be included under theRetirement Savings and Investment Plan; $1,200caption ‘‘Executive Compensation’’ inadministrative feesthe Proxy Statement is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The information to be included under the
Cash Balance Pension Plan; $135,000 awarded under the Long-Term Incentive Plan;caption ‘‘Security Ownership of Certain Beneficial Owners and$27,837 for insurance. For Mr. Dunn, this amount includes the following: $3,000 under the Retirement Savings and Investment Plan; $1,200 in administrative fees under the Cash Balance Pension Plan; $71,400 awarded under the Long-Term Incentive Plan; and $20,095 for insurance. For Mr. Eastin, this amount includes the following: $3,000 under the Retirement Savings and Investment Plan; $1,200 in administrative fees under the Cash Balance Pension Plan; $67,575 awarded under the Long-Term Incentive Plan; and $19,946 for insurance. For Mr. Plante, this amount includes the following: $2,700 under the Retirement Savings and Investment Plan; $1,200 in administrative fees under the Cash Balance Pension Plan; $32,400 awarded under the Long-Term Incentive Plan; and $2,738 for insurance. For Mr. Jolly, this amount includes the following: $2,738 under the Retirement Savings and Investment Plan; $1,200 in administrative fees under the Cash Balance Pension Plan; $27,375 awarded under the Long-Term Incentive Plan; and $19,130 for insurance. 36RETIREMENT BENEFITS The following table sets forth the annual benefits upon retirement at age 65 in 2003, without regard to statutory maximums, for various combinations of final average earnings and lengths of service which may be payable to Messrs. Alexander, Dunn, Eastin, Plante and Jolly under the Pension Plan for Eligible Employees of the Operating Partnership and its Subsidiaries and/or the Suburban Propane Company Supplemental Executive Retirement Plan. Each such plan has been assumed by the Partnership and each such person will be credited for service earned under such plan to date. Messrs. Alexander, Dunn, and Eastin have 7 years, 6 years and 4 years, respectively, under both plans. For vesting purposes, however, Mr. Alexander has 19 years combined service with the Partnership and his prior service with Hanson Industries. Messrs. Plante and Jolly have 26 years and 6 years, respectively, under the Pension Plan. Benefits under the Pension Plan are limited to IRS statutory maximums for defined benefit plans. Currently, the statutory maximum for defined benefit plan is $200,000.
Pension Plan Annual Benefit for Years of Credited Service Shown (1,2,3,4,5,6) Average Earnings 5 Yrs. 10 Yrs. 15 Yrs. 20 Yrs. 25 Yrs. 30 Yrs. 35 Yrs. - -------- ------ ------- ------- ------- ------- ------- -------$100,000 7,888 15,775 23,663 31,551 39,438 47,326 55,214 $200,000 16,638 33,275 49,913 66,551 83,188 99,826 116,464 $300,000 25,388 50,775 76,163 101,551 126,938 152,326 177,714 $400,000 34,138 68,275 102,413 136,551 170,688 204,826 238,964 $500,000 42,888 85,775 128,663 171,551 214,438 257,326 300,2141 The Plans' definition of earnings consists of base pay only. 2 Annual Benefits are computed on the basis of straight life annuity amounts. The pension benefit is calculated as the sum of (a) plus (b) multiplied by (c) where (a) is that portion of final average earnings up to 125% of social security Covered Compensation times 1.4% and (b) is that portion of final average earnings in excess of 125% of social security Covered Compensation times 1.75% and (c) is credited service up to a maximum of 35 years. 3 Effective January 1, 1998, the Plan was amended to a cash balance benefit formula for current and future Plan participants. Initial account balances were established based upon the actuarial equivalent value of the accrued December 31, 1997 prior plan benefit. Annual interest credits and pay-based credits will be credited to this account. The 2002 pay-based credits for Messrs. Alexander, Dunn, Eastin, Plante and Jolly are 3.0%, 2.0%, 1.5%, 10.0% and 2.0%, respectively. Participants as of December 31, 1997 will receive the greater of the cash balance benefit and the prior plan benefit through the year 2002. The Plan was amended effective January 1, 2000. Pursuant to this amendment, individuals who are hired or rehired on or after January 1, 2000 are not eligible to participateManagement’’ in thePlan. 4 In addition, a supplemental cash balance account was established equal to the value of certain benefits related to retiree medical and vacation benefits. An initial account value was determined for those active employees who were eligible for retiree medical coverage as of April 1, 1998 equal to $415 multipliedProxy Statement is incorporated herein byyears of benefit service (maximum of 35 years). Future pay-based credits and interest are credited to this account. The 2002 pay-based credits for Messrs. Alexander, Dunn, Eastin, Plante and Jolly are 2.0%, 0.0%, 0.0%, 2.0% and 0.0%, respectively. 5 Effective January 1, 2003, all future pay-based credits as determined under the cash balance benefit formula were discontinued. Interest credits continue to be applied based on the five-year U.S. Treasury bond rate in effect during the preceding November, plus one percent. 6 Effective January 1, 2003 the annual benefits accrued by Messrs. Alexander, Dunn and Eastin pursuant to the Supplemental Executive Retirement Plan (in excess of the statutory limitations governing the Pension Plan) were, in the aggregate, approximately $100,000. 37SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN We have adopted a non-qualified, unfunded supplemental retirement plan known as the Supplemental Executive Retirement Plan (the "SERP"). The purpose of the SERP is to provide certain executive officers with a level of retirement income from us, without regard to statutory maximums, including the IRS limitation for defined benefit plans. Effective January 1, 1998, the Pension Plan for Eligible Employees of Suburban Propane, L.P. (the "Qualified Plan") was amended and restated as a cash balance plan. In light of the conversion of the Qualified Plan to a cash balance formula, the SERP has been 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 described under the Retirement Benefits section above, applied to the amount of Annual Compensation that exceeds the IRS statutory maximums for defined benefit plans which is currently $200,000. Messrs. Alexander, Dunn, and Eastin currently participate in the SERP. Effective January 1, 2003, the SERP was discontinued with a frozen benefit determined for Messrs. Alexander, Dunn and Eastin. Provided that the SERP requirements are met, Mr. Alexander will receive a monthly benefit of $6,031, Mr. Dunn will receive a monthly benefit of $347.30 and Mr. Eastin will receive a monthly benefit of $1,053.18. In the event of a change in control involving the Partnership, the SERP will terminate effective on the close of business 30 days following the change in control. Each participant will be deemed retired and will have his benefit determined as of the date the plan is terminated with payment of the benefit no later than 90 days after the change in control. Each participant will receive a lump sum payment equivalent to the present value of each participant's benefit payable under this 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, which ever is less, as the discount rate to determine the present value of accrued benefit. LONG-TERM INCENTIVE PLAN We have adopted a non-qualified, unfunded long-term incentive plan for officers and key employees, effective October 1, 1997 (the "LTIP"). Payout of the LTIP will follow the normal vesting schedule of each participant. Awards are based on a percentage of base pay and are subject to the achievement of certain performance criteria, including our ability to earn sufficient funds and make cash distributions on our Common Units with respect to each fiscal year. Awards vest over time with one-third vesting at the beginning of years three, four, and five from the award date. We will terminate this plan effective September 30, 2004. Effective October 1, 2002 we adopted a new non-qualified, unfunded long-term incentive plan for officers and key employees. The new plan measures our performance as Total Return to Unitholders ("TRU") relative to a predetermined peer group, primarily composed of other Master Limited Partnerships, approved by our Compensation Committee. Awards are granted in three year performance cycles based on a quartile ranking of TRU compared to the peer group. Target awards for each participant are a percentage of base salary. Long-Term Incentive Plan awards earned in fiscal 2003 were as follows:
Performance or Other Period Award Until Maturation Potential Awards Under Plan Name FY 2003 or Payout Threshold Target Maximum - ---- ------- --------- --------- ------ -------Mark A. Alexander $135,000 3-5 Years $ 0 $135,000 $135,000 Michael J. Dunn, Jr. 71,400 3-5 Years 0 71,400 71,400 David R. Eastin 67,575 3-5 Years 0 67,575 67,575 Robert M. Plante 32,400 3-5 Years 0 32,400 32,400 Jeffrey S. Jolly 27,375 3-5 Years 0 27,375 27,37538EMPLOYMENT AGREEMENT We entered into an employment agreement (the "Employment Agreement") with Mr. Alexander, which became effective March 5, 1996 and was amended October 23, 1997 and April 14, 1999. 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 Employment Agreement. The Employment Agreement for Mr. Alexander provides for an annual base salary of $450,000 as of September 28, 2002 and provides for Mr. Alexander to earn a bonus up to 100% of annual base salary (the "Maximum Annual Bonus") for services rendered based upon certain performance criteria. The Employment Agreement also provides for the opportunity to participate in benefit plans made available to our other senior executives and senior managers. We also provide Mr. Alexander with term life insurance with a face amount equal to three times his annual base salary. For the purposes of this section "change of control" means the occurrence during the employment term of: (i) an acquisition of our Common Units or voting equity interests by any person other than the Partnership, the General Partner or any of our affiliates immediately after which such person beneficially owns more than 25% of the combined voting power of our then outstanding units: unless such acquisition was made by (a) us or our subsidiaries, or any employee benefit plan maintained by us, our Operating Partnership or any of our subsidiaries, or (b) by any person in a transaction where (A) the existing holders prior to the transaction own at least 60% of the voting power of the entity surviving the transaction and (B) none of the Unitholders other than the Partnership, our subsidiaries, any employee benefit plan maintained by us, our Operating Partnership, or the surviving entity, or the existing beneficial owner of more than 25% of the outstanding units owns more than 25% of the combined voting power of the surviving entity (such transaction, Non-Control Transaction): (ii) approval by our partners of (a) merger, consolidation or reorganization involving the Partnership other than a Non-Control Transaction: (b) a complete liquidation or dissolution of the Partnership: or (c) the sale or other disposition of 50% or more of our net assets to any person (other than a transfer to a subsidiary). If a "change of control" of the Partnership occurs and within six months prior thereto or at any time subsequent to such change of control we terminate the Executive's employment without "cause" or the Executive resigns with "good reason" or the Executive terminates his employment during the six month period commencing on the six month anniversary and ending on the twelve month anniversary of a "change of control", then Mr. Alexander will be entitled to (i) a lump sum severance payment equal to three times the sum of his annual base salary in effect as of the date of termination and the Maximum Annual Bonus, and (ii) medical benefits for three years from the date of such termination. The Employment Agreement provides that if any payment received by Mr. Alexander is subject to the 20% federal excise tax under Section 4999 of the Internal Revenue Code, the payment will be grossed up 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. Mr. Alexander also participates in the SERP, which provides retirement income which could not be provided under our qualified plans by reason of limitations contained in the Internal Revenue Code. SEVERANCE PROTECTION PLAN FOR KEY EMPLOYEES Our officers and key employees are provided with employment protection following a "change of control" (the "Severance Protection Plan"). For the purposes of this section "change of control" means the occurrence during the employment term of: (i) an acquisition of our Common Units or voting equity interests by any person other than the Partnership, our General Partner or any of their affiliates immediately after which such person beneficially owns more than 25% of the combined voting power of our then outstanding units: unless such acquisition was made by (a) us or our subsidiaries, or any employee benefit plan maintained by us, our Operating Partnership or any of our subsidiaries, or (b) by any person in a transaction where (A) the existing holders prior to the transaction own at least 60% of the voting power of the entity surviving the transaction and (B) none of the 39Unitholders other than the Partnership, our subsidiaries, any employee benefit plan maintained by us, our Operating Partnership, or the surviving entity, or the existing beneficial owner of more than 25% of the outstanding units owns more than 25% of the combined voting power of the surviving entity (such transaction a "Non-Control Transaction"): (ii) approval by our partners of (a) merger, consolidation or reorganization involving the Partnership other than a Non-Control Transaction: (b) a complete liquidation or dissolution of the Partnership: or (c) the sale or other disposition of 50% or more of our net assets to any person (other than a transfer to a subsidiary). The Severance Protection Plan provides for severance payments equal to sixty-five (65) weeks of base pay and target bonuses for such officers and key employees following a "change of control" and termination of employment. This group comprises approximately forty-three (43) individuals. Pursuant to their severance protection agreements, Messrs. Dunn, Eastin, Plante and Jolly, as our executive officers, have been granted severance protection payments of seventy-eight (78) weeks of base pay and target bonuses following a "change in control" and termination of employment in lieu of participation in the Severance Protection Plan. Our Compensation Committee has also granted severance protection payments of seventy-eight (78) weeks to four other executive officers who do not participate in the Severance Protection Plan. COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION IN COMPENSATION DECISIONS Compensation of our executive officers is determined by the Compensation Committee of our Board of Supervisors. The Compensation Committee is comprised of Messrs. Stookey, Mecum and Logan, none of whom are our officers or employees. COMPENSATION OF SUPERVISORS Mr. Stookey, who is the Chairman of the Board of Supervisors, receives annual compensation of $75,000 for his services to us. Mr. Logan and Mr. Mecum, the other two Elected Supervisors, receive $50,000 per year and Mr. Mark J. Anton, who serves as Supervisor Emeritus, receives $15,000 per year. All Elected Supervisors and the Supervisor Emeritus receive reimbursement of reasonable out-of-pocket expenses incurred in connection with meetings of the Board of Supervisors. We do not pay any additional remuneration to our employees (or employees of any of our affiliates) or employees of our General Partner or any of its affiliates for serving as members of the Board of Supervisors. 40ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The following table sets forth certain information as of November 21, 2003 regarding the beneficial ownership of Common Units and Incentive Distribution Rights by each member of the Board of Supervisors, each executive officer named in the Summary Compensation table, all members of the Board of Supervisors and executive officers as a group and each person or group known by us (based upon filings under Section 13(d) or (g) under The Securities Exchange Act of 1934) to own beneficially more than 5% thereof. Except as set forth in the notes to the table, the business address of each individual or entity in the table is c/o Suburban Propane Partners, L.P., 240 Route 10 West, Whippany, New Jersey 07981-0206 and each individual or entity has sole voting and investment power over the Common Units reported.
SUBURBAN PROPANE, L.P. - ---------------------- Amount and Nature of Percent Title of Class Name of Beneficial Owner Beneficial Ownership of Class - -------------- ------------------------ -------------------- --------Common Units Mark A. Alexander (a) 29,000 * Michael J. Dunn, Jr. (a) 0 - David R. Eastin 11,000 - Robert M. Plante 12,262 - Jeffrey S. Jolly 3,000 - John Hoyt Stookey 11,519 * Harold R. Logan, Jr. 15,064 * Dudley C. Mecum 5,634 * Mark J. Anton (b) 4,600 * All Members of the Board of Supervisors and Executive Officers as a Group (13 persons) 92,079 * Goldman, Sachs & Co. (c) 1,709,003 6.3% 85 Broad Street Common Units New York, NY 10004 Incentive Distribution Suburban Energy Services Rights Group LLC N/A N/A* Less than 1%. (a) Excludes the following numbers of Common Units as to which the following individuals deferred receipt as described below; Mr. Alexander - 243,902 and Mr. Dunn - 48,780. These Common Units are held in trust pursuant to a Compensation Deferral Plan, and Mr. Alexander and Mr. Dunn will have no voting or investment power over these Common Units until they are distributed by the trust. Mr. Alexander and Mr. Dunn have elected to receive the quarterly cash distributions on these deferred units. Notwithstanding the foregoing, if a "change of control" of the Partnership occurs (as defined in the Compensation Deferral Plan), all of the deferred Common Units (and related distributions) held in the trust automatically become distributable to the members. (b) Mr. Anton shares voting and investment power over 3,600 Common Units with his wife and over 1,000 Common Units with Lizmar Partners, L.P., a family owned limited partnership of which he is its general partner. (c) Holder reports having shared voting power with respect to all of the Common Units and shared dispositive power with respect to all of the Common Units. 41reference. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.The information to be included under the caption ‘‘Executive Compensation — Certain Relationships and Related Transactions’’ in the Proxy Statement is incorporated herein by reference.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The
following table sets forthinformation to be included under theaggregate fees for services related to fiscal years 2003caption ‘‘Principal Accounting Fees and2002 provided by PricewaterhouseCoopers LLP, our principal accountants. Fiscal Fiscal 2003 2002 -------------------- ------------------- Audit Fees (a) $ 599,000 $ 474,000 Audit-Related Fees (b) 206,000 12,000 Tax Fees (c) 590,000 772,600 All Other Fees (d) -- 179,900 (a) Audit Fees represent fees billed for professional services rendered for the audit of our annual financial statements and review of our quarterly financial statements, and audit services provided in connection with other statutory or regulatory filings, including services related to our June 2003 public offering of Common Units. (b) Audit-Related Fees represent fees billed for assurance services related to the audit of our financial statements. The amount shown for fiscal 2003 consists primarily of services related to current and future compliance with the provisions of the Sarbanes-Oxley Act of 2002. The amount shown for fiscal 2002 consists of services related to the stand-alone audit of the financial statements of Suburban Energy Service Group LLC, our General Partner. In addition to these amounts, fees for services related to the audits of the Partnership's defined benefit pension plan and defined contribution plan financial statements, paid by the individual plans, were $31,000 and $29,500 for the fiscal 2003 and 2002 audits, respectively. (c) Tax Fees represent fees for professional services related to tax reporting, compliance and transaction services assistance. (d) All Other Fees represent fees for services provided to us not otherwise includedServices’’ in thecategories above. The amount shown for fiscal 2002 consists primarily of services related to operational control reviews. The Audit Committee of the Board of Supervisors has adopted a formal policy concerning the approval of audit and non-audit services to be providedProxy Statement is incorporated herein bythe principal accountant, 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 2003 and reviewed all audit and non-audit services for fiscal 2002. 42reference.PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
AND REPORTS ON FORM 8-K (a) The following documents are filed as part of this Report: 1. (i) Financial Statements
(a) The following documents are filed as part of this Annual Report:
1. Financial Statements See
"Index‘‘Index to FinancialStatements"Statements’’ set forth on page F-1.(ii) Supplemental
2. Financial Statement Schedule See ‘‘Index to Financial
Information Balance Sheet Information of Suburban Energy Services Group LLC See "Index to Supplemental Financial Information"Statement Schedule’’ set forth on pageF-24. 2. Financial Statement ScheduleS-1.
3. Exhibits See
"Index‘‘Index toFinancial Statement Schedule"Exhibits’’ set forth on pageS-1. 3. Exhibits See "Index to Exhibits" set forth on pageE-1.(b) Reports on Form 8-K No reports were filed on form 8-K. 43SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Suburban Propane Partners, L.P. Date: December 2, 2003 By: /s/ MARK A. ALEXANDER -------------------------------- Mark A. Alexander President, Chief Executive Officer and Appointed Supervisor
SUBURBAN PROPANE PARTNERS, L.P. Date: December 5, 2005 By: /s/ MARK A. ALEXANDER
Mark A. Alexander
Chief Executive Officer and
Appointed 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:
Signature Title Date --------- ----- ----/s/ MICHAEL J. DUNN, JR Senior Vice/s/ MARK A. ALEXANDER Chief Executive Officer and Appointed Supervisor December 5, 2005 (MarkA. Alexander) /s/ MICHAEL J. DUNN, JR. President - Corporateand Appointed SupervisorDecember 2, 2003 - --------------------------------- Development (Michael5, 2005(Michael J. Dunn, Jr.) Suburban Propane Partners, L.P. Appointed Supervisor /s/ JOHN HOYT STOOKEY/S/ JOHN HOYT STOOKEY Chairman and Elected Supervisor December 2, 2003 - --------------------------------- (John5, 2005(John Hoyt Stookey) /s/ HAROLD/s/ HAROLD R. LOGAN, JR. LOGAN, JR.Elected Supervisor December 2, 2003 - --------------------------------- (Harold5, 2005(Harold R. Logan, Jr.) /s/ DUDLEY/s/ DUDLEY C. MECUM Elected Supervisor December 5, 2005 (Dudley C. MECUM Elected Supervisor December 2, 2003 - --------------------------------- (Dudley C.Mecum)/s/ ROBERT M. PLANTE/s/ ROBERT M. PLANTE Vice President and December 2, 2003 - ---------------------------------Chief Financial Officer(RobertDecember 5, 2005 (Robert M. Plante) Suburban Propane Partners, L.P. /s/ MICHAEL/s/ MICHAEL A. STIVALA Controller and Chief Accounting Officer December 5, 2005 (Michael A. STIVALA Controller December 2, 2003 - --------------------------------- Suburban Propane Partners, L.P. (Michael A.Stivala)44INDEX TO EXHIBITS
The exhibits listed on this Exhibit Index are filed as part of this Annual Report. Exhibits required to be filed by Item 601 of Regulation S-K, which are not listed below, are not applicable.
Exhibit Number Description ------ ----------- D 2.1 Recapitalization Agreement dated as of November 27, 1998 by and among the Partnership, the Operating Partnership, the General Partner, Millennium and Suburban Energy Services Group LLC. E 3.1 Second Amended and Restated Agreement of Limited Partnership of the Partnership dated as of May 26, 1999. E 3.2 Second Amended and Restated Agreement of Limited Partnership of the Operating Partnership dated as of May 26, 1999. A 10.3 Note Agreement dated as of February 28, 1996 among certain investors and the Operating Partnership relating to $425 million aggregate principal amount of 7.54% Senior Notes due June 30, 2011. K 10.4 Amendment No. 1 to the Note Agreement dated May 13, 1998 among certain investors and the Operating Partnership relating to $425 million aggregate principal amount of 7.54% Senior Notes due June 30, 2011. K 10.5 Amendment No. 2 to the Note Agreement dated March 29, 1999 among certain investors and the Operating Partnership relating to $425 million aggregate principal amount of 7.54% Senior Notes due June 30, 2011. K 10.6 Amendment No. 3 to the Note Agreement dated December 6, 2000 among certain investors and the Operating Partnership relating to $425 million aggregate principal amount of 7.54% Senior Notes due June 30, 2011. I 10.7 Amendment No. 4 to the Note Agreement dated March 21, 2002 among certain investors and the Operating Partnership relating to $425 million aggregate principal amount of 7.54% Senior Notes due June 30, 2011. K 10.8 Amendment No. 5 to the Note Agreement dated November 20, 2002 among certain investors and the Operating Partnership relating to $425 million aggregate principal amount of 7.54% Senior Notes due June 30, 2011. E-1
Exhibit
NumberDescription 2.1 Recapitalization Agreement dated as of November 27, 1998 by and among the Partnership, the Operating Partnership, the General Partner, Millennium and Suburban Energy Services Group LLC. (Incorporated by reference to Exhibit 2.1 to the Partnership’s Current Report on Form 8-K filed December 3, 1998). 3.1 Second Amended and Restated Agreement of Limited Partnership of the Partnership dated as of May 26, 1999. (Incorporated by reference to the Partnership’s Proxy Statement filed pursuant to Section 14(a) of the Securities Exchange Act of 1934 on April 22, 1999). 3.2 Second Amended and Restated Agreement of Limited Partnership of the Operating Partnership dated as of May 26, 1999. (Incorporated by reference to the Partnership’s Proxy Statement filed pursuant to Section 14(a) of the Securities Exchange Act of 1934 on April 22, 1999). 4.1 Indenture, dated as of December 23, 2003, between Suburban Propane Partners, L.P., Suburban Energy Finance Corp. and The Bank of New York, as Trustee (including Form of Senior Global Exchange Note). (Incorporated by reference to Exhibit 10.28 to the Partnership’s Quarterly Report on Form 10-Q For the fiscal quarter ended December 27, 2003). 4.2 Exchange and Registration Rights Agreement, dated December 23, 2003 among Suburban Propane Partners, L.P., Suburban Energy Finance Corp., Wachovia Capital Markets, LLC and Goldman, Sachs & Co. (Incorporated by reference to Exhibit 4.1 to the Partnership’s registration statement on Form S-4 dated December 19, 2003). 4.3 Exchange and Registration Rights Agreement, dated March 31, 2005 among Suburban Propane Partners, L.P., Suburban Energy Finance Corp., Wachovia Capital Markets, LLC and Goldman, Sachs & Co. (Incorporated by reference to Exhibit 4.1 to the Partnership’s Current Report of Form 8-K filed April 1, 2005). 10.1 Employment Agreement dated as of March 5, 1996 between the Operating Partnership and Mr. Alexander. (Incorporated by reference to Exhibit 10.13 to the Partnership’s Current Report on Form 8-K filed April 29, 1996). 10.2 First Amendment to Employment Agreement dated as of March 5, 1996 between the Operating Partnership and Mr. Alexander entered into as of October 23, 1997. (Incorporated by reference to Exhibit 10.13 to the Partnership’s Current Report on Form 8-K filed April 29, 1996). 10.3 Second Amendment to Employment Agreement dated as of March 5, 1996 between the Operating Partnership and Mr. Alexander entered into as of April 14, 1999. (Incorporated by reference to Exhibit 10.15 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 27, 1997). 10.4 Form of Third Amendment to Employment Agreement dated as of March 5, 1996 between the Operating Partnership and Mr. Alexander, entered into November 2, 2005 (filed herewith). 10.5 Suburban Propane Partners, L.P. 2000 Restricted Unit Plan. (Incorporated by reference to Exhibit 10.16 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 30, 2000). I 10.9 Guaranty Agreement dated as of April 11, 2002 provided by four direct subsidiaries of Suburban Propane, L.P. for the 7.54% Senior Notes due June 30, 2011. I 10.10 Intercreditor Agreement dated March 21, 2002 between First Union National Bank, the Lenders under the Operating Partnership's Amended and Restated Credit Agreement and the Noteholders of the Operating Partnership's 7.54% Senior Notes due June 30, 2011. J 10.11 Note Agreement dated as of April 19, 2002 among certain investors and the Operating Partnership relating to $42.5 million aggregate principal amount of 7.37% Senior Notes due June 30, 2012. J 10.12 Guaranty Agreement dated as of July 1, 2002 provided by certain subsidiaries of Suburban Propane, L.P. for the 7.37% Senior Notes due June 30, 2012. A 10.13 Employment Agreement dated as of March 5, 1996 between the Operating Partnership and Mr. Alexander. C 10.14 First Amendment to Employment Agreement dated as of March 5, 1996 between the Operating Partnership and Mr. Alexander entered into as of October 23, 1997. F 10.15 Second Amendment to Employment Agreement dated as of March 5, 1996 between the Operating Partnership and Mr. Alexander entered into as of April 14, 1999. A 10.16 The Partnership's 1996 Restricted Unit Plan. G 10.17 Suburban Propane Partners, L.P. 2000 Restricted Unit Plan. B 10.18 The Partnership's Severance Protection Plan dated September 1996. K 10.19 Suburban Propane L.P. Long-Term Incentive Plan as amended and restated effective October 1, 1999. F 10.20 Benefits Protection Trust dated May 26, 1999 by and between Suburban Propane Partners, L.P. and First Union National Bank. F 10.21 Compensation Deferral Plan of Suburban Propane Partners, L.P. and Suburban Propane, L.P. dated May 26, 1999. H 10.22 First Amendment to the Compensation Deferral Plan of Suburban Propane Partners, L.P. and Suburban Propane, L.P. dated November 5, 2001. H 10.23 Amended and Restated Supplemental Executive Retirement Plan of the Partnership (effective as of January 1, 1998). H 10.24 Amended and Restated Retirement Savings and Investment Plan of Suburban Propane (effective as of January 1, 1998). K 10.25 Amendment No. 1 to the Retirement Savings and Investment Plan of Suburban Propane (effective January 1, 2002). L 10.26 Second Amended and Restated Credit Agreement dated May 8, 2003. M 10.27 First Amendment to Second Amended and Restated Credit Agreement dated November 4, 2003. E-2
Exhibit
NumberDescription 10.6 The Partnership’s Severance Protection Plan dated September 1996. (Incorporated by reference to Exhibit 10.18 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 28, 1996). 10.7 Form of Amendment to Suburban Propane Severance Protection Plan for Key Employees, adopted November 2, 2005 (filed herewith). 10.8 Suburban Propane, L.P. Long Term Incentive Plan, as amended and restated effective October 1, 1999. (Incorporated by reference to Exhibit 10.19 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 28, 2002). 10.9 Form of Amendment to Suburban Propane, L.P. Long Term Incentive Program, adopted November 2, 2005 (filed herewith). 10.10 Suburban Propane L.P. 2003 Long Term Incentive Plan. (Incorporated by reference to Exhibit 10.7 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 25, 2004). 10.11 Benefits Protection Trust dated May 26, 1999 by and between Suburban Propane Partners, L.P. and First Union National Bank. (Incorporated by reference to the Partnership’s Quarterly Report on Form 10-Q for the fiscal quarter ended June 26, 1999). 10.12 Compensation Deferral Plan of Suburban Propane Partners, L.P. and Suburban Propane, L.P. amended and restated as of January 1, 2004. (Incorporated by reference to Exhibit 10. 9 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 25, 2004). 10.13 Form of Amendment to Compensation Deferral Plan of Suburban Propane Partners, L.P. and Suburban Propane, L.P., adopted November 2, 2005 (filed herewith). 10.14 Amended and Restated Supplemental Executive Retirement Plan of the Partnership (effective as of January 1, 1998). (Incorporated by reference to Exhibit 10.23 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 29, 2001). 10.15 Amended and Restated Retirement Savings and Investment Plan of Suburban Propane effective as of January 1, 1998). (Incorporated by reference to Exhibit 10.24 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 29, 2001). 10.16 Amendment No. 1 to the Retirement Savings and Investment Plan of Suburban Propane (effective January 1, 2002). (Incorporated by reference to Exhibit 10.25 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 28, 2002). 10.17 Third Amended and Restated Credit Agreement dated October 20, 2004, as amended by the First Amendment thereto dated March 17, 2005, as further amended by the Second Amendment thereto dated August 25, 2005. (Incorporated by reference to the Partnership’s Current Report on Form 8-K filed August 29, 2005). 10.18 First Amendment to the Third Amended and Restated Credit Agreement dated as of March 11, 2005 (Incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed April 1, 2005). M 21.1 Listing of Subsidiaries of the Partnership. M 23.1 Consent of Independent Accountants. M 31.1 Certification of the President and Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. M 31.2 Certification of the Vice President and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. M 32.1 Certification of the President and Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. M 32.2 Certification of the Vice President and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. - -------------------------------------------------------------------------------- A Incorporated by reference to the same numbered Exhibit to the Partnership's Current Report on Form 8-K filed April 29, 1996. B Incorporated by reference to the same numbered Exhibit to the Partnership's Annual Report on Form 10-K for the fiscal year ended September 28, 1996. C Incorporated by reference to the same numbered Exhibit to the Partnership's Annual Report on Form 10-K for the fiscal year ended September 27, 1997. D Incorporated by reference to Exhibit 2.1 to the Partnership's Current Report on Form 8-K filed December 3, 1998. E Incorporated by reference to the Partnership's Proxy Statement filed pursuant to Section 14(a) of the Securities Exchange Act of 1934 on April 22, 1999. F Incorporated by reference to the Partnership's Quarterly Report on Form 10-Q for the fiscal quarter ended June 26, 1999. G Incorporated by reference to Exhibit 10.16 to the Partnership's Annual Report on Form 10-K for the fiscal year ended September 30, 2000. H Incorporated by reference to the same numbered Exhibit to the Partnership's Annual Report on Form 10-K for the fiscal year ended September 29, 2001. I Incorporated by reference to the Partnership's Quarterly Report on Form 10-Q for the fiscal quarter ended March 30, 2002. J Incorporated by reference to the Partnership's Quarterly Report on Form 10-Q for the fiscal quarter ended June 29, 2002. E-3
Exhibit
NumberDescription 10.19 Second Amendment to the Third Amended and Restated Credit Agreement dated as of August 26, 2005 (Incorporated by reference to the Partnership’s Current Report on Form 8-K filed August 29, 2005). 10.20 Asset Purchase Agreement by and Among Agway Energy Products, LLC, Agway Energy Services, Inc., Agway Energy Services PA, Inc., Agway, Inc. and Suburban Propane, L.P., dated as of November 10, 2003 (incorporated by reference to Exhibit 10.28 to the Partnership's Current Report on Form 8-K filed December 5, 2003). 14.1 Code of Ethics. (Incorporated by reference to Exhibit 14.1 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 25, 2004). 21.1 Subsidiaries of Suburban Propane Partners, L.P. (incorporated by reference to Exhibit 21.1 of the Partnership’s Annual Report on Form 10-K for the year ended September 25, 2004). 23.1 Consent of Independent Registered Public Accounting Firm. (Filed herewith). 31.1 Certification of the Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. (Filed herewith). 31.2 Certification of the Vice President and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. (Filed herewith). 32.1 Certification of the Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (Filed herewith). 32.2 Certification of the Vice President and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (Filed herewith). K Incorporated by reference to the same numbered Exhibit to the Partnership's Annual Report on Form 10-K for the fiscal year ended September 28, 2002. L Incorporated by reference to the same numbered Exhibit to the Partnership's Quarterly Report on Form 10-Q for the fiscal quarter ended March 29, 2003. M Filed herewith. E-4INDEX TO FINANCIAL STATEMENTS
SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES
Page ----
Page Report of Independent Registered Public Accounting Firm F-2 Consolidated Balance Sheets –
As of September 24, 2005 and September 25, 2004F-4 Consolidated Statements of Operations –
Years Ended September 24, 2005, September 25, 2004 and September 27, 2003F-5 Consolidated Statements of Cash Flows –
Years Ended September 24, 2005, September 25, 2004 and September 27, 2003F-6 Consolidated Statements of Partners’ Capital –
Years Ended September 24, 2005, September 25, 2004 and September 27, 2003F-7 Notes to Consolidated Financial Statements F-8 Report of Independent
Auditors...............................................F-2 Consolidated Balance Sheets - As of September 27, 2003 and September 28, 2002............................F-3 Consolidated Statements of Operations - Years Ended September 27, 2003, September 28, 2002 and September 29, 2001.........................................................F-4 Consolidated Statements of Cash Flows - Years Ended September 27, 2003, September 28, 2002 and September 29, 2001.........................................................F-5 Consolidated Statements of Partners' Capital - Years Ended September 27, 2003, September 28, 2002 and September 29, 2001.........................................................F-6 Notes to Consolidated Financial Statements...................................F-7 F-1REPORT OF INDEPENDENT AUDITORSRegistered Public Accounting FirmTo the Board of Supervisors and Unitholders of
Suburban Propane Partners, L.P.:We have completed an integrated audit of Suburban Propane Partners, L.P.’s 2005 consolidated financial statements and of its internal control over financial reporting as of September 24, 2005 and audits of its 2004 and 2003 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.
Consolidated financial statements and financial statement schedule
In our opinion, the consolidated financial statements listed in the index appearing under Item
15.(a)1.(i)15(a)(1) present fairly, in all material respects, the financial position of Suburban Propane Partners, L.P. and its subsidiaries(the "Partnership")at September27, 200324, 2005 and September28, 200225, 2004, and the results of their operations and their cash flows for each of the threefiscalyears in the period ended September27, 200324, 2005 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 Item15.(a)2.15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of thePartnership's management; ourPartnership’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance withauditingthe standardsgenerally accepted inof theUnited States of America, whichPublic Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes 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. We believe that our audits provide a reasonable basis for our opinion.Internal control over financial reporting
Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A, that Suburban Propane Partners, L.P. maintained effective internal control over financial reporting as of September 24, 2005 based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of September 24, 2005, based on criteria established in Internal Control – Integrated Framework issued by the COSO. The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Partnership’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PRICEWATERHOUSECOOPERS LLP
PricewaterhouseCoopers LLP
Florham Park,NJ October 23, 2003 F-2New Jersey
December 5, 2005SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in
(in thousands)
September September 27, 2003 28, 2002 ---------------- ----------------- ASSETS Current assets:Cash and cash equivalents $ 15,765 $ 40,955 Accounts receivable, less allowance for doubtful accounts of $2,519 and $1,894, respectively 36,437 33,002 Inventories 41,510 36,367 Prepaid expenses and other current assets 5,200 6,465 ---------------- ----------------- Total current assets 98,912 116,789 Property, plant and equipment, net 312,790 331,009 Goodwill 243,236 243,260 Other intangible assets, net 1,035 1,474 Other assets 9,657 7,614 ---------------- ----------------- Total assets $ 665,630 $ 700,146 ================ ================= LIABILITIES AND PARTNERS' CAPITAL Current liabilities: Accounts payable $ 26,204 $ 27,412 Accrued employment and benefit costs 20,798 21,430 Current portion of long-term borrowings 42,911 88,939 Accrued insurance 7,810 8,670 Customer deposits and advances 23,958 26,125 Accrued interest 7,457 8,666 Other current liabilities 8,575 6,303 ---------------- ----------------- Total current liabilities 137,713 187,545 Long-term borrowings 340,915 383,830 Postretirement benefits obligation 33,435 33,284 Accrued insurance 20,829 18,299 Accrued pension liability 42,136 53,164 Other liabilities 6,524 4,738 ---------------- ----------------- Total liabilities 581,552 680,860 ---------------- ----------------- Commitments and contingencies Partners' capital: Common Unitholders (27,256 and 24,631 units issued and outstanding at September 27, 2003 and September 28, 2002, respectively) 165,950 103,680 General Partner 1,567 1,924 Deferred compensation (5,795) (11,567) Common Units held in trust, at cost 5,795 11,567 Unearned compensation (2,171) (1,924) Accumulated other comprehensive loss (81,268) (84,394) ---------------- ----------------- Total partners' capital 84,078 19,286 ---------------- ----------------- Total liabilities and partners' capital $ 665,630 $ 700,146 ================ ================= The accompanying notes are an integral part of these consolidated financial statements.F-3
SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (in thousands, except per unit amounts) Year Ended ------------------------------------------------------- September September September 27, 2003 28, 2002 29, 2001 ------------- ---------------- ----------------Revenues Propane $ 680,741 $ 570,280 $ 839,607 Other 90,938 94,825 91,929 ------------- ---------------- ---------------- 771,679 665,105 931,536 Costs and expenses Cost of products sold 376,783 289,055 510,313 Operating 250,698 234,140 258,735 General and administrative 36,661 30,771 32,511 Depreciation and amortization 27,520 28,355 36,496 Gain on sale of storage facility - (6,768) - ------------- ---------------- ---------------- 691,662 575,553 838,055 ------------- ---------------- ---------------- Income before interest expense and provision for income taxes 80,017 89,552 93,481 Interest income (334) (600) (414) Interest expense 33,963 35,925 40,010 ------------- ---------------- ---------------- Income before provision for income taxes 46,388 54,227 53,885 Provision for income taxes 202 703 375 ------------- ---------------- ---------------- Income from continuing operations 46,186 53,524 53,510 Discontinued operations (Note 14): Gain on sale of customer service centers 2,483 - - ------------- ---------------- ---------------- Net income $ 48,669 $ 53,524 $ 53,510 ============= ================ ================ General Partner's interest in net income $ 1,193 $ 1,362 $ 1,048 ------------- ---------------- ---------------- Limited Partners' interest in net income $ 47,476 $ 52,162 $ 52,462 ============= ================ ================ Income per Common Unit - basic Income from continuing operations $ 1.78 $ 2.12 $ 2.14 Discontinued operations 0.09 - - ------------- ---------------- ---------------- Net income $ 1.87 $ 2.12 $ 2.14 ------------- ---------------- ---------------- Weighted average number of Common Units outstanding - basic 25,359 24,631 24,514 ------------- ---------------- ---------------- Income per Common Unit - diluted Income from continuing operations $ 1.77 $ 2.12 $ 2.14 Discontinued operations 0.09 - - ------------- ---------------- ---------------- Net income $ 1.86 $ 2.12 $ 2.14 ------------- ---------------- ---------------- Weighted average number of Common Units outstanding - diluted 25,495 24,665 24,530 ------------- ---------------- ---------------- The accompanying notes are an integral part of these consolidated financial statements.F-4
SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands) Year Ended ------------------------------------------------------- September September September 27, 2003 28, 2002 29, 2001 ---------------- ----------------- ----------------- Cash flows from operating activities:Net income $ 48,669 $ 53,524 $ 53,510 Adjustments to reconcile net income to net cash provided by operations: Depreciation expense 27,097 27,857 28,517 Amortization of intangible assets 423 498 7,979 Amortization of debt origination costs 1,291 1,338 2,006 Amortization of unearned compensation 863 985 440 Gain on disposal of property, plant and equipment, net (636) (546) (3,843) Gain on sale of customer service centers (2,483) - - Gain on sale of storage facility - (6,768) - Changes in assets and liabilities, net of dispositions: (Increase)/decrease in accounts receivable (4,101) 9,635 18,601 (Increase)/decrease in inventories (5,339) 5,402 (260) Decrease/(increase) in prepaid expenses and other current assets 576 (2,526) 1,699 Decrease in accounts payable (1,208) (10,862) (21,109) (Decrease)/increase in accrued employment and benefit costs (632) (8,518) 10,969 (Decrease)/increase in accrued interest (1,209) 348 147 (Decrease)/increase in other accrued liabilities (1,825) (1,153) 4,635 (Increase)/decrease in other noncurrent assets (2,506) (439) 1,194 Decrease in other noncurrent liabilities (1,680) - (2,647) ---------------- ----------------- ----------------- Net cash provided by operating activities 57,300 68,775 101,838 ---------------- ----------------- ----------------- Cash flows from investing activities: Capital expenditures (14,050) (17,464) (23,218) Proceeds from sale of property, plant and equipment, net 1,994 2,625 5,311 Proceeds from sale of customer service centers, net 7,197 - - Proceeds from sale of storage facility, net - 7,988 - ---------------- ----------------- ----------------- Net cash used in investing activities (4,859) (6,851) (17,907) ---------------- ----------------- ----------------- Cash flows from financing activities: Long-term debt repayments (88,939) (408) (44,428) Short-term debt repayments, net - - (6,500) Credit agreement expenses (826) - (730) Net proceeds from issuance of Common Units 72,186 - 47,079 Partnership distributions (60,052) (57,055) (54,503) ---------------- ----------------- ----------------- Net cash used in financing activities (77,631) (57,463) (59,082) ---------------- ----------------- ----------------- Net (decrease)/increase in cash and cash equivalents (25,190) 4,461 24,849 Cash and cash equivalents at beginning of year 40,955 36,494 11,645 ---------------- ----------------- ----------------- Cash and cash equivalents at end of year 15,765 40,955 36,494 ================ ================= ================= Supplemental disclosure of cash flow information: Cash paid for interest $ 33,635 $ 34,134 $ 37,774 ================ ================= ================= Non-cash adjustment for minimum pension liability $ (4,938) $ 37,800 $ 47,277 ================ ================= ================= The accompanying notes are an integral part of these consolidated financial statements.F-5
SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL (in thousands) Accumu- lated Other Compre- Number of Deferred Common Unearned hensive Total Compre- Common Common General Compen- Units Held Compen- (Loss)/ Partners' hensive Units Unitholders Partner sation in Trust sation Income Capital Income ----- ------------------- ------ -------- ------ ------ ------- ------Balance at September 30, 2000 22,278 $ 58,474 $ 1,866 $ (11,567) $ 11,567 $ (640) $ 2,129 $ 61,829 Net income 52,462 1,048 53,510 $53,510 Other comprehensive income: Unrealized holding loss (1,046) (1,046) (1,046) Less: Reclassification adjustment for gains included in net income (1,083) (1,083) (1,083) Minimum pension liability adjustment (47,277) (47,277) (47,277) -------- Comprehensive income $ 4,104 ======== Partnership distributions (53,477) (1,026) (54,503) Sale of Common Units under public offering, net of offering expenses 2,353 47,079 47,079 Grants issued under Restricted Unit Plan, net of forfeitures 1,011 (1,011) - Amortization of Compensation Deferral Plan 212 212 Amortization of Restricted Unit Plan, net of forfeitures 228 228 --------- --------- --------- -------- -------- -------- -------- --------- Balance at September 29, 2001 24,631 105,549 1,888 (11,567) 11,567 (1,211) (47,277) 58,949 Net income 52,162 1,362 53,524 $53,524 Other comprehensive income: Net unrealized gains on cash flow hedges 838 838 838 Less: Reclassification of realized gains on cash flow hedges into earnings (155) (155) (155) Minimum pension liability adjustment (37,800) (37,800) (37,800) -------- Comprehensive income $ 16,407 ======== Partnership distributions (55,729) (1,326) (57,055) Grants issued under Restricted Unit Plan, net of forfeitures 1,698 (1,698) - Amortization of Compensation Deferral Plan 382 382 Amortization of Restricted Unit Plan, net of forfeitures 603 603 --------- --------- --------- -------- -------- -------- -------- --------- Balance at September 28, 2002 24,631 103,680 1,924 (11,567) 11,567 (1,924) (84,394) 19,286 Net income 47,476 1,193 48,669 $48,669 Other comprehensive income: Net unrealized losses on cash flow hedges (1,129) (1,129) (1,129) Less: Reclassification of realized gains on cash flow hedges into earnings (683) (683) (683) Minimum pension liability adjustment 4,938 4,938 4,938 -------- Comprehensive income $ 51,795 ======== Partnership distributions (58,502) (1,550) (60,052) Sale of Common Units under public offering, net of offering expenses 2,625 72,186 72,186 Distribution of Common Units held in trust 5,772 (5,772) - Grants issued under Restricted Unit Plan, net of forfeitures 1,110 (1,110) - Amortization of Restricted Unit Plan, net of forfeitures 863 863 --------- --------- --------- -------- -------- -------- -------- --------- Balance at September 27, 2003 27,256 $ 165,950 $ 1,567 $ (5,795) $ 5,795 $ (2,171) $(81,268) $ 84,078 ========= ========= ========= ======== ======== ======== ======== =========
September 24,
2005September 25,
2004ASSETS Current assets: Cash and cash equivalents $ 14,411 $ 53,481 Accounts receivable, less allowance for doubtful accounts of $9,965 and $7,896, respectively 109,918 91,000 Inventories 80,565 64,141 Prepaid expenses and other current assets 31,909 44,272 Total current assets 236,803 252,894 Property, plant and equipment, net 399,985 406,702 Goodwill 281,359 282,015 Other intangible assets, net 20,685 25,582 Other assets 26,765 24,814 Total assets $ 965,597 $ 992,007 LIABILITIES AND PARTNERS' CAPITAL Current liabilities: Accounts payable $ 63,569 $ 60,664 Accrued employment and benefit costs 20,291 25,152 Short-term borrowings 26,750 — Current portion of long-term borrowings 475 42,940 Accrued insurance 11,505 12,724 Customer deposits and advances 62,099 61,265 Accrued interest 10,975 10,067 Other current liabilities 26,548 32,152 Total current liabilities 222,212 244,964 Long-term borrowings 548,070 472,975 Postretirement benefits obligation 31,058 31,616 Accrued insurance 34,952 25,517 Accrued pension liability 40,206 35,035 Other liabilities 12,983 13,782 Total liabilities 889,481 823,889 Commitments and contingencies Partners' capital: Common Unitholders (30,279 and 30,257 units issued and outstanding at September 24, 2005 and September 25, 2004, respectively) 159,199 238,880 General Partner (1,779 ) 852 Deferred compensation (5,887 ) (5,778 ) Common Units held in trust, at cost 5,887 5,778 Unearned compensation (4,355 ) (3,845 ) Accumulated other comprehensive loss (76,949 ) (67,769 ) Total partners' capital 76,116 168,118 Total liabilities and partners' capital $ 965,597 $ 992,007 The accompanying notes are an integral part of these consolidated financial statements.
F-6SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TOCONSOLIDATED
FINANCIALSTATEMENTS(dollarsOF OPERATIONS
(in thousands, except per unit amounts)1. PARTNERSHIP ORGANIZATION
Year Ended September 24,
2005September 25,
2004September 27,
2003Revenues Propane $ 969,943 $ 856,109 $ 680,840 Fuel oil and refined fuels 431,223 281,682 — Natural gas and electricity 102,803 68,452 — HVAC 106,115 92,072 46,938 Other 10,150 8,939 7,297 1,620,234 1,307,254 735,075 Costs and expenses Cost of products sold 1,067,248 779,029 358,582 Operating 396,235 361,696 232,462 General and administrative 47,191 53,888 36,661 Restructuring costs (Note 7) 2,775 2,942 — Impairment of goodwill (Note 6) 656 3,177 — Depreciation and amortization 37,762 36,743 27,520 1,551,867 1,237,475 655,225 Income before interest expense, loss on debt extinguishment and provision for income taxes 68,367 69,779 79,850 Loss on debt extinguishment 36,242 — — Interest income (310 ) (429 ) (334 ) Interest expense 40,684 41,261 33,963 (Loss) income before provision for income taxes (8,249 ) 28,947 46,221 Provision for income taxes 803 3 202 (Loss) income from continuing operations (9,052 ) 28,944 46,019 Discontinued operations (Note 17): Gain on sale of customer service centers 976 26,332 2,483 (Loss) income from discontinued service centers — (972 ) 167 Net (loss) income $ (8,076 ) $ 54,304 $ 48,669 General Partner's interest in net (loss) income $ (251 ) $ 1,310 $ 1,193 Limited Partners' interest in net (loss) income $ (7,825 ) $ 52,994 $ 47,476 (Loss) income per Common Unit – basic (Loss) income from continuing operations $ (0.29 ) $ 0.96 $ 1.77 Discontinued operations 0.03 0.83 0.10 Net (loss) income $ (0.26 ) $ 1.79 $ 1.87 Weighted average number of Common Units outstanding – basic 30,276 29,599 25,359 (Loss) income per Common Unit – diluted (Loss) income from continuing operations $ (0.29 ) $ 0.96 $ 1.76 Discontinued operations 0.03 0.82 0.10 Net (loss) income $ (0.26 ) $ 1.78 $ 1.86 Weighted average number of Common Units outstanding – diluted 30,276 29,705 25,495 The accompanying notes are an integral part of these consolidated financial statements.
SUBURBAN PROPANE PARTNERS, L.P. AND
FORMATIONSUBSIDIARIESCONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
Year Ended September 24,
2005September 25,
2004September 27,
2003Cash flows from operating activities: Net (loss) income $ (8,076 ) $ 54,304 $ 48,669 Adjustments to reconcile net income to net cash provided by operations: Depreciation expense 32,865 33,344 27,097 Amortization of intangible assets 4,897 3,399 423 Amortization of debt origination costs 1,514 1,421 1,291 Amortization of unearned compensation 1,806 1,171 863 Amortization of discount on long-term borrowings 117 — — Gain on disposal of property, plant and equipment, net (2,043 ) (715 ) (636 ) Gain on sale of customer service centers (976 ) (26,332 ) (2,483 ) Pension settlement charge — 5,337 — Impairment of goodwill 656 3,177 — Loss on debt extinguishment 36,242 — — Changes in assets and liabilities, net of businesses acquired and of dispositions: (Increase)/decrease in accounts receivable (18,918 ) 10,047 (4,101 ) (Increase) in inventories (16,424 ) (10,677 ) (5,339 ) Decrease/(increase) in prepaid expenses and other current assets 4,315 (13,155 ) 576 Increase/(decrease) in accounts payable 3,326 17,603 (1,208 ) (Decrease)/increase in accrued employment and benefit costs (4,861 ) 1,024 (632 ) Increase/(decrease) in accrued interest 908 2,610 (1,209 ) (Decrease)/increase in other accrued liabilities (5,989 ) 20,233 (1,825 ) (Increase)/decrease in other noncurrent assets (3,552 ) 619 (7,435 ) Increase/(decrease) in other noncurrent liabilities 13,198 (10,345 ) 3,249 Net cash provided by operating activities 39,005 93,065 57,300 Cash flows from investing activities: Capital expenditures (29,301 ) (26,527 ) (14,050 ) Acquisition of Agway Energy, net of cash acquired — (211,181 ) — Proceeds from sale of property, plant and equipment 4,670 1,799 1,994 Proceeds from sale of customer service centers, net — 39,352 7,197 Net cash used in investing activities (24,631 ) (196,557 ) (4,859 ) Cash flows from financing activities: Long-term debt repayments (340,440 ) (42,911 ) (88,939 ) Long-term debt issuance, net of discount 372,953 175,000 — Short-term borrowings 26,750 — — Expenses associated with debt agreements (4,175 ) (5,947 ) (826 ) Prepayment premium associated with debt extinguishment (31,980 ) — — Net proceeds from issuance of Common Units — 87,566 72,186 Partnership distributions (76,552 ) (72,500 ) (60,052 ) Net cash (used in)/provided by financing activities (53,444 ) 141,208 (77,631 ) Net (decrease)/increase in cash and cash equivalents (39,070 ) 37,716 (25,190 ) Cash and cash equivalents at beginning of year 53,481 15,765 40,955 Cash and cash equivalents at end of year 14,411 53,481 15,765 Supplemental disclosure of cash flow information: Cash paid for interest $ 42,457 $ 35,252 $ 33,635 Non-cash adjustment for minimum pension liability $ (1,242 ) $ 2,096 $ (4,938 ) The accompanying notes are an integral part of these consolidated financial statements.
SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(in thousands)
Number of
Common
UnitsCommon
UnitholdersGeneral
PartnerDeferred
CompensationCommon
Units
Held in
TrustUnearned
CompensationAccumulated
Other
Comprehensive
(Loss)/IncomeTotal
Partners'
CapitalComprehensive
Income/(Loss)Balance at September 28 , 2002 24,631 $ 103,680 $ 1,924 $ (11,567 ) $ 11,567 $ (1,924 ) $ (84,394 ) $ 19,286 Net income 47,476 1,193 48,669 $ 48,669 Other comprehensive income: Net unrealized losses on cash flow hedges (1,129 ) (1,129 ) (1,129 ) Less: Reclassification of realized gains on cash flow hedges into earnings (683 ) (683 ) (683 ) Minimum pension liability adjustment 4,938 4,938 4,938 Comprehensive income $ 51,795 Partnership distributions (58,502 ) (1,550 ) (60,052 ) Sale of Common Units under public offering, net of offering expenses 2,625 72,186 72,186 Distribution of Common Units held in trust 5,772 (5,772 ) — Grants issued under Restricted Unit Plan, net of forfeitures 1,110 (1,110 ) — Amortization of Restricted Unit Plan, net of forfeitures 863 863 Balance at September 27 , 2003 27,256 165,950 1,567 (5,795 ) 5,795 (2,171 ) (81,268 ) 84,078 Net income 52,994 1,310 54,304 $ 54,304 Other comprehensive income: Net unrealized gains on cash flow hedges 9,129 9,129 9,129 Less: Reclassification of realized losses on cash flow hedges into earnings 1,129 1,129 1,129 Non-cash pension settlement charge 5,337 5,337 5,337 Minimum pension liability adjustment (2,096 ) (2,096 ) (2,096 ) Comprehensive income $ 67,803 Partnership distributions (70,475 ) (2,025 ) (72,500 ) Sale of Common Units under public offering, net of offering expenses 2,990 87,566 87,566 Common Units issued under Restricted Unit Plan 11 Common Units distributed into trust (159 ) 159 — Distribution of Common Units held in trust 176 (176 ) — Grants issued under Restricted Unit Plan, net of forfeitures 2,845 (2,845 ) — Amortization of Restricted Unit Plan, net of forfeitures 1,171 1,171 Balance at September 25, 2004 30,257 238,880 852 (5,778 ) 5,778 (3,845 ) (67,769 ) 168,118 Net loss (7,825 ) (251 ) (8,076 ) $ (8,076 ) Other comprehensive income/(loss): Net unrealized losses on cash flow hedges (1,293 ) (1,293 ) (1,293 ) Less: Reclassification of realized gains on cash flow hedges into earnings (9,129 ) (9,129 ) (9,129 ) Minimum pension liability adjustment 1,242 1,242 1,242 Comprehensive loss $ (17,256 ) Partnership distributions (74,172 ) (2,380 ) (76,552 ) Common Units issued under Restricted Unit Plan 22 Common Units distributed into trust (109 ) 109 — Grants issued under Restricted Unit Plan, net of forfeitures 2,316 (2,316 ) — Amortization of Restricted Unit Plan, net of forfeitures 1,806 1,806 Balance at September 24, 2005 30,279 $ 159,199 $ (1,779 ) $ (5,887 ) $ 5,887 $ (4,355 ) $ (76,949 ) $ 76,116 The accompanying notes are an integral part of these consolidated financial statements.
SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands, except per unit amounts)
1. Partnership Organization and Formation Suburban Propane Partners, L.P. (the
"Partnership"‘‘Partnership’’)was formed on December 19, 1995 asis a publicly traded Delaware limitedpartnership. The Partnershippartnership principally engaged, through its operating partnership andits subsidiary, Suburban Propane, L.P. (the "Operating Partnership"), were formed to acquire and operate the propane business and assets of Suburban Propane, a division of Quantum Chemical Corporation (the "Predecessor Company"). In addition, Suburban Sales & Service, Inc. (the "Service Company"), a subsidiary of the Operating Partnership, was formed to acquire and operate the service work and appliance and parts businesses of the Predecessor Company. The Partnership, the Operating Partnership and the Service Company commenced operations on March 5, 1996 upon consummation of an initial public offering of 21,562,500 common units representing limited partner interestssubsidiaries, in thePartnership (the "Common Units"),retail marketing and distribution of propane, fuel oil and other refined fuels, as well as theprivate placementmarketing of$425,000 aggregate principal amount of Senior Notes due 2011 issued by the Operating Partnership and the transfer of all of the propane assets (excluding the net accounts receivable balance) of the Predecessor Company to the Operating Partnership and the Service Company. On January 5, 2001, Suburban Holdings, Inc., a subsidiary of the Operating Partnership, was formed to hold the stock of Gas Connection, Inc., Suburban @ Home, Inc. and Suburban Franchising, Inc. Gas Connection, Inc. (d/b/a HomeTown Hearth & Grill) sells and installsnatural gas andpropane gas grills, fireplaceselectricity in deregulated markets. In addition, to complement its core marketing andrelated accessoriesdistribution businesses, the Partnership installs andsupplies; Suburban @ Home, Inc. sells, installs,servicesand repairsafull rangewide variety of home comfort equipment, particularly for heating, ventilation and air conditioningproducts; and Suburban Franchising, Inc. creates and develops propane related franchising business opportunities. The Partnership, the Operating Partnership, the Service Company, Suburban Holdings, Inc. and its subsidiaries are collectively referred to hereinafter as the "Partnership Entities." From March 5, 1996 through May 26, 1999, Suburban Propane GP, Inc. (the "Former General Partner"(‘‘HVAC’’), a wholly-owned indirect subsidiary of Millennium Chemicals, Inc., served as the general partner of the Partnership and the Operating Partnership owning a 1% general partner interest in the Partnership and a 1.0101% general partner interest in the Operating Partnership. In addition, the Former General Partner owned a 24.4% limited partner interest evidenced by 7,163,750 Subordinated Units and a special limited partner interest in the Partnership. On May 26, 1999, the Partnership completed a recapitalization (the "Recapitalization") which included the redemption of the Subordinated Units and special limited partner interest from the Former General Partner, and the substitution of Suburban Energy Services Group LLC (the "General Partner") as the new general partner of the Partnership and the Operating Partnership following the General Partner's purchase of the combined 2.0101% general partner interests for $6,000 in cash. The General Partner is owned by senior management of the Partnership and, following the public offerings discussed in Note 13, owns a combined 1.71% general partner interest in the Partnership and the Operating Partnership.. The limited partner interests in the Partnership are evidenced byCommon Unitscommon units traded on the New York StockExchange.Exchange (‘‘Common Units’’), with 30,279,059 Common Units outstanding at September 24, 2005. The limited partners are entitled to participate in distributions and exercise the rights and privileges available to limited partners under the Second Amended and Restated Agreement of Limited Partners (the ‘‘Partnership Agreement’’), such as the election of three of the five members of the Board of Supervisors and vote 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,
Entities are engagedthe Operating Partnership and the Service Company commenced operations in March 1996 in connection with the Partnership’s initial public offering.The general partner of both the Partnership and the Operating Partnership is Suburban Energy Services Group LLC (the ‘‘General Partner’’), a Delaware limited liability company. The General Partner is majority-owned by senior management of the Partnership and owns a combined 1.54% general partner interest in the
retailPartnership andwholesale marketingthe Operating Partnership. The General Partner appoints two of the five members of the Board of Supervisors.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. and Suburban Franchising, Inc. HomeTown Hearth & Grill sells and installs natural gas and propane gas grills, fireplaces and related
appliancesaccessories andservices.supplies. Suburban @ Home sells, installs, services and repairs a full range of HVAC products. Suburban Franchising creates and develops propane related franchising business opportunities.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 other refined fuels and HVAC assets and businesses of Agway Energy acquired on December 23, 2003 (see Note 3). 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 9).
The Partnership serves
approximately 750,000more than 1,000,000 active residential, commercial, industrial and agricultural customers from approximately320370 customer service centers in4030 states. ThePartnership'sPartnership’s operations are concentrated in the east and west coast regions of the United States. No single customer accounted for 10% orF-7more of the Partnership'sPartnership’s revenues during fiscal2003, 20022005, 2004 or2001.2003. During fiscal2003, 20022005, 2004 and2001,2003, three suppliers provided approximately42%33%,49%36% and47%42%, respectively, of thePartnership'sPartnership’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.2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES PRINCIPLES OF CONSOLIDATION.
2. Summary of Significant Accounting Policies Principles of Consolidation. The consolidated financial statements include the accounts of the Partnership
Entities.and all of its direct and indirect subsidiaries. All significant intercompany transactions and account balances have been eliminated. The Partnership consolidates the results of operations, financial condition and cash flows of the Operating Partnership as a result of thePartnership'sPartnership’s 98.9899% limited partner interest in the Operating Partnership and its ability to influence control over the major operating and financial decisions through the powers of the Board of Supervisors provided for in theSecond Amended and Restated Agreement of Limited Partnership. FISCAL PERIOD.Partnership Agreement.Fiscal Period. The
Partnership'sPartnership’s fiscal year ends on the last Saturday nearest to September 30.REVENUE RECOGNITION.Revenue Recognition. Sales of propane, fuel oil and other 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
repairrepairs, maintenance andmaintenanceother service activities is recognized upon completion of the service.USE OF ESTIMATES.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 insurance and litigation reserves, environmental reserves, pension and other postretirement benefit liabilities and costs, valuation of derivative instruments, depreciation and amortization of long-lived assets, asset valuation assessment, as well as the allowance 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.Cash and Cash Equivalents. The Partnership considers all highly liquid debt 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. Inventories are stated at the lower of cost or market. Cost is determined using a weighted average method for propane, fuel oil and other refined fuels and natural gas, and a standard cost basis for appliances, which approximates average cost.
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES.Derivative Instruments and Hedging Activities. The Partnership
is exposed to the impactenters into a combination ofmarket fluctuations in the commodity price of propane. The Partnership routinely uses commodityexchange-traded futuresforwardand option contracts, forward contracts and in certain instances, over-the-counter options (collectively, ‘‘derivative instruments’’) tohedge its commoditymanage 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 derivative instruments are reported on the balance sheet, within other current assets or other current liabilities, at their fairvalues.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 and 149 (‘‘SFAS 133’’). 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.Prior to March 31, 2002,Changes in thePartnership determined that itsfair value of derivative instrumentsdid not qualifyare recorded each period in current period earnings or other comprehensive income (loss) (‘‘OCI’’), depending on whether a derivative instrument is designated ashedgesa hedge and,as such,if so, thechanges in fair values were recorded in income. Beginning with contracts entered into subsequent to March 31, 2002, a portiontype ofthe derivative instruments entered into by the Partnership have been designated and qualify as cash flow hedges.hedge. For derivative instruments designated as cash flow hedges, the Partnership formally assesses, both at the hedgecontract'scontract’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 inaccumulated other comprehensive (loss)/incomeOCI 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 incost of products soldoperating expenses immediately. Changes in the fair value of derivative instruments that are not designated as hedges are recordedF-8in current period earnings within operating expenses. LONG-LIVED ASSETS.expenses and reclassified to cost of products sold once realized.A portion of the Partnership’s option contracts are not classified as hedges and, as such, changes in the fair value of these derivative instruments are recognized within operating expenses as they occur. The value of certain option contracts that do qualify as hedges and are designated as cash flow hedges under SFAS 133 have two components of value: time value and intrinsic value. The intrinsic value is the value by which the option is in the money (i.e., the amount by which the value of the commodity exceeds the exercise or ‘‘strike’’ price of the option). The remaining amount of option value is attributable to time value. The Partnership does not include the time value of option contracts in its assessment of hedge effectiveness and, therefore, records changes in the time value component of the options currently in earnings.
Market risks associated with the trading of 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. Open inventory positions are also reviewed and managed daily as to exposures to changing market prices.
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 new Term Loan facility under the Revolving Credit Agreement (see Note 9). 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. At September 24, 2005, the fair value of the interest rate swap amounted to $1,293 and is included within other liabilities.
Long-Lived Assets. Long-lived assets include:
PROPERTY, PLANT AND EQUIPMENT.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'sasset’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 for related groups of assets under the straight-line method based upon their estimated useful lives as follows:Buildings 40 Years Building and land improvements 10-40 Years Transportation equipment 4-30 Years Storage facilities 20 Years Equipment, primarily tanks and cylinders 3-40 Years Computer software 3-7 Years
Buildings 40 Years Building and land improvements 10-40 Years Transportation equipment 4-30 Years Storage facilities 7-40 Years Equipment, primarily tanks and cylinders 3-40 Years Computer software 3-7 Years The Partnership reviews the recoverability of long-lived assets when circumstances occur that indicate that the carrying value of an asset group may not be recoverable. Such circumstances include a significant adverse change in the manner in which an asset group is being used, current operating losses combined with a history of operating losses experienced by the asset group or a current expectation that an asset group 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'sPartnership’s ability to recover the value of the asset group from the future undiscounted cash flows expected to result from the use and eventual disposition of the asset group. 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 group exceeds its fair value. The fair value of an asset group 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. Goodwill represents the excess of the purchase price over the fair value of net assets acquired.
Effective September 30, 2001, the beginning of the Partnership's 2002 fiscal year, the Partnership elected to early adopt the provisions of Statement of Financial Accounting Standards ("SFAS") No. 142, "Goodwill and Other Intangible Assets" ("SFAS 142"). As a result of the adoption of SFAS 142, goodwill is no longer amortized to expense, ratherGoodwill is subject to an impairment review at a reporting unit level, on an annual basis in August of eachyear, 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
either (i) a market value approach taking into consideration the quoted market price of Common Units; or (ii)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.OTHER INTANGIBLE ASSETS.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 exceeds the implied fair value of the goodwill.Other Intangible Assets. Other intangible assets consist
primarilyof non-compete agreementswhichand 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 years20042006 and2011. ACCRUED INSURANCE.2010. 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 2006 and 2019.Accrued Insurance. Accrued insurance represents the estimated costs of known and anticipated or unasserted claims under the
Partnership'sPartnership’s general and product,workers'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, the Partnership records a self-insurance provision up to the estimated amount of the probable claimor the amount of the deductible, whichever is lower,utilizing actuarially determined lossF-9development 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 5 years of origination. INCOME TAXES.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
Entities consiststructure consists of two limited partnerships, the Partnership and the Operating Partnership, andfiveseveral corporateentities.entities (the ‘‘Corporate Entities’’). For federalandincome 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, no recognition of income tax expense has been reflected in thePartnership'sPartnership’s consolidated financial statements relating to the earnings of the Partnership and the Operating Partnership. The earnings attributable to thecorporate entitiesCorporate Entities are subject to federal and state income taxes. Accordingly, thePartnership'sPartnership’s consolidated financial statements reflect income tax expense related to certain states that require income tax at the corporateentities' earnings.level, as well as for the earnings of the Corporate Entities. 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 entitiesCorporate 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.UNIT-BASED COMPENSATION.Unit-Based Compensation. The Partnership accounts for unit-based compensation in accordance with Accounting Principles Board Opinion No. 25,
"Accounting‘‘Accounting for Stock Issued toEmployees"Employees’’, and related interpretations. Upon award of restricted units under thePartnership'sPartnership’s 2000 Restricted Unit Plan, unearned compensation equivalent to the market price of the Restricted Units on the date of grant is established as a reduction ofpartners'partners’ capital. The unearned compensation is amortized ratably to expense over the restricted periods. The Partnership follows the disclosure only provision of SFAS No. 123,"Accounting‘‘Accounting for Stock-BasedCompensation" ("Compensation’’ (‘‘SFAS123"123’’). Pro forma net income and net income per Common Unit under the fair value method of accounting for Restricted Units under SFAS 123 would be the same as reported net income and net income per Common Unit.COSTS AND EXPENSES.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 other refined fuels, as well as the cost of natural gas and electricity sold, including transportation costs to deliver product from the
Partnership'sPartnership’s supply points to storage or to thePartnership'sPartnership’s customer service centers. Cost of products sold also includes the cost of appliances, equipment and related parts sold or installed by thePartnership'sPartnership’s customer service centers computed on a basis that approximates the average cost of the products. 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'sPartnership’s retail propane, fuel oil and other 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 thePartnership'sPartnership’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.
F-10NET INCOME PER UNIT.Net Income Per Unit. Basic net income per Common Unit, for each of the periods presented, is computed by dividing net income, after deducting the General
Partner'sPartner’s approximate2%3.1% interest, by the weighted average number of outstanding Common Units. Diluted net income per Common Unit is computed by dividing net income, after deducting the GeneralPartner'sPartner’s approximate2%3.1% interest, by the weighted average number of outstanding Common Units and time vested Restricted Units granted under the 2000 Restricted Unit Plan. Diluted net loss per Common Unit for the year ended September 24, 2005 does not include 134,471 Restricted Units as their effect would be anti-dilutive. In computing diluted net income per Common Unit, weighted average units outstanding used to compute basic net income per Common Unit were increased by136,000 units and 34,000105,711 units for theyearsyear ended September27, 2003 and September 28, 2002, respectively,25, 2004 to reflect the potential dilutive effect of the time vested Restricted Units outstanding using the treasury stock method. Net income is allocated to the Common Unitholders and the General Partner in accordance with their respective Partnership ownership interests, after giving effect to any priority income allocations for incentive distributions allocated to the General Partner.COMPREHENSIVE INCOME.Computations of earnings per Common Unit are 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 Common Units and participating securities according to distributions declared and participation rights in undistributed earnings, as if all of the earnings were distributed to limited partners and the general partner (inclusive of the incentive distribution rights of the General Partner which are considered participating securities for purposes of the application of EITF 03-6). EITF 03-6 was adopted by the Partnership at the end of fiscal 2004. However, the requirements of EITF 03-6 do not apply to the computation of net income (loss) per Common Unit in periods in which a net loss is reported and therefore did not have any impact on annual net loss per Common Unit for the year ended September 24, 2005. In addition, the application of EITF 03-6 on the
computation of our net income per Common Unit for the year ended September 25, 2004 did not have any impact on annual net income per Common Unit. EITF 03-6 may have an impact on the computation of net income per Common Unit on a quarterly basis, depending on the level of net income in relation to distributions declared.
Comprehensive Income. The Partnership reports comprehensive (loss)/income (the total of net income and all other non-owner changes in
partners'partners’ capital) within the consolidated statement ofpartners'partners’ capital. Comprehensive (loss)/income includes unrealized gains and losses on derivative instruments accounted for as cash flow hedges and minimum pension liability adjustments.RECENTLY ISSUED ACCOUNTING STANDARDS.Recently Issued Accounting Standards. In
June 2002,March 2005, the Financial Accounting Standards Board (the"FASB"‘‘FASB’’) issuedSFASFASB Interpretation No.146, "Accounting47, ‘‘Accounting forCosts Associated with Exit or Disposal Activities" ("SFAS 146"Conditional Asset Retirement Obligations’’ (‘‘FIN 47’’).SFAS 146FIN 47 clarifies the term conditional asset retirement obligation as a legal obligation to retire an asset when the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. FIN 47 also requirescompaniesan entity to recognizecosts associateda liability for the fair value of the conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. FIN 47 is effective beginning withexit or disposal activities when they are incurred rather than atthedate of a commitment to an exit or disposal plan.Partnership’s fiscal year ending September 30, 2006. The Partnership is currently evaluating the provisions ofSFAS 146 are effective for exit or disposal activities initiated after December 31, 2002. The provisions of this standardFIN 47 and currently believes that adoption willbe applied by the Partnership on an ongoing basis, as applicable. In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" ("SFAS 149"). SFAS 149 amends SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts. This statement is effective for contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003. The adoption of this standard didnot have a materialimpacteffect onthe Partnership's consolidatedits financial position, results of operations or cash flows.In
May 2003,December 2004, the FASB issued a revised SFAS No.150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" ("123, ‘‘Share-Based Payment’’ (‘‘SFAS150"123R’’). SFAS150 establishes standards123R is a revision of SFAS No. 123 ‘‘Accounting for Stock-Based Compensation’’ and supersedes APB Opinion No. 25 ‘‘Accounting for Stock Issued to Employees’’. SFAS 123R requires a public entity to measure theclassificationcost of employee services received in exchange for an award of equity instruments based on the grant date fair value of the award. SFAS 123R eliminates the alternative of using the APB Opinion No. 25 intrinsic value method of accounting that was provided for in SFAS No. 123 as originally issued andmeasurement of certain financial instruments with characteristics of both liabilities and equity. Itrequires thatan issuer classify athe compensation cost relating to share-based payment transactions be recognized in the financialinstrument that is within its scope as a liability (or an asset in some circumstances). Many of these instruments were previously required to be classified as equity. This statementstatements. SFAS 123R is effectivefor financialbeginning with the Partnership’s fiscal year ending September 30, 2006. The Partnership has historically recognized unearned compensation associated with awards of equity instrumentsentered into or modified after May 31, 2003, and otherwise is effective forratably to expense over thePartnership's fourth quarter in fiscal 2003. Thevesting period (see Note 10). Accordingly, adoption ofthis standard didSFAS 123R is not expected to havea materialan impact on thePartnership'sPartnership’s consolidated financial position, results ofoperationsoperation or cash flows.In January 2003, the FASB issued FASB Interpretation No. 46, "Consolidation of Variable Interest Entities" ("FIN 46"), an interpretation of Accounting Research Bulletin No. 51, "Consolidated Financial Statements." FIN 46 addresses consolidation by business enterprises of variable interest entities that meet certain characteristics. The consolidation requirements of FIN 46 apply immediately to variable interest entities created after January 31, 2003. The consolidation requirements apply to variable interest entities created before February 1, 2003 in the first fiscal year or interim period beginning after June 15, 2003. However, in October 2003, the FASB deferred the effective date for applying certain provisions F-11of FIN 46 and in November 2003, issued an exposure draft which would amend certain provisions of FIN 46. As a result of the latest exposure draft, the Partnership is currently evaluating the impact, if any, that FIN 46 or any future amendment may have on its financial position and results of operations. RECLASSIFICATIONS.Reclassifications. Certain prior period amounts have been reclassified to conform with the current period presentation.
3. DISTRIBUTIONS OF AVAILABLE CASH
3. Acquisition of Agway Energy On 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. The total cost of the Agway Acquisition, including the purchase price of $205,055 (net of a working capital adjustment paid to the Partnership of $945), $2,650 for non-compete agreements with certain members of the management of Agway Energy and $3,500 in transaction related costs, was approximately $211,205.
The Agway Acquisition was financed with net proceeds of $87,566 from the issuance of 2,990,000 Common Units in December 2003 (see Note 16) and a portion of the net proceeds from the offering of unsecured 6.875% senior notes (see Note 9). The results of Agway Energy have been included in the Partnership’s consolidated financial statements from the date of the Agway Acquisition. The cost of the Agway Acquisition was allocated to the assets acquired and liabilities assumed according to estimated fair values as follows:
Net current assets $ 31,241 Property, plant and equipment 112,187 Intangible assets 28,046 Goodwill 41,956 Other assets, principally environmental escrow asset (see Note 14) 13,750 Deferred tax assets 21,519 Deferred tax asset valuation allowance (21,519 ) Severance and other restructuring costs (2,225 ) Environmental reserve (see Note 14) (13,750 ) Total cost of Agway Acquisition $ 211,205 The following unaudited pro forma information presents the results of operations of the Partnership as if the Agway Acquisition had occurred at the beginning of the periods presented. The pro forma information, however, is not necessarily indicative of the results of operations assuming the Agway Acquisition had occurred at the beginning of the periods presented, nor is it necessarily indicative of future results.
Year Ended September 25,
2004September 27,
2003As reported Revenues $ 1,307,254 $ 735,075 Income from continuing operations 28,944 46,019 Income from continuing operations per Common Unit – basic $ 0.96 $ 1.77 Pro Forma Revenues $ 1,475,579 $ 1,424,552 Income from continuing operations 33,235 56,302 Income from continuing operations per Common Unit – basic $ 1.10 $ 2.17 The as reported and pro forma income from continuing operations for the year ended September 25, 2004 above includes the restructuring charge of $2,942 as further described in Note 7 below, the $5,337 non-cash pension settlement charge described in Note 12 below and the $3,177 non-cash charge for the impairment of goodwill described in Note 6 below. These charges were not reflected in the pro forma results for the year ended September 27, 2003.
4. Distributions of Available Cash The Partnership makes distributions to its partners approximately 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
Second Amended and RestatedPartnership 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 thePartnership'sPartnership’s business, the payment of debt principal and interest and for distributions during the next four quarters. Distributions by the Partnership in an amount equal to 100% of its Available Cash will generally be made98.29%98.46% to the Common Unitholders and1.71%1.54% to the General Partner, subject to the payment of incentive distributions to the General Partner to the extent the quarterly distributions exceed a target distribution of $0.55 per Common Unit.As defined in the
Second Amended and RestatedPartnership Agreement, the General Partner has certain Incentive Distribution Rights("IDRs"(‘‘IDRs’’) which represent 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,98.29%98.46% of the Available Cash is distributed to the Common Unitholders and1.71%1.54% is distributed to the General Partner(98.11%(98.29% and 1.71%, respectively, prior to the December 2003 public offering and 98.11% and 1.89%, respectively, prior to the June 2003 public offering described in Note13)16). With regard to the balance of quarterly distributions in excess of the $0.55 per Common Unit target distribution, 85% of the Available Cash is distributed to the Common Unitholders and 15% is distributed to the General Partner.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
27, 2003:24, 2005:
September 27, September 28, September 29, 2003 2002 2001 -------------------- --------------------- --------------------First Quarter $ 0.5750 $ 0.5625 $ 0.5375 Second Quarter 0.5750 0.5625 0.5500 Third Quarter 0.5875 0.5750 0.5500 Fourth Quarter 0.5875 0.5750 0.5625
September 24,
2005September 25,
2004September 27,
2003First Quarter $ 0.6125 $ 0.5875 $ 0.5750 Second Quarter 0.6125 0.6000 0.5750 Third Quarter 0.6125 0.6125 0.5875 Fourth Quarter 0.6125 0.6125 0.5875 On October
23, 2003,19, 2005, thePartnershipBoard of Supervisors declared a quarterly distribution of$0.5875$0.6125 per Common Unitor $2.35 on an annualized basis, forin respect of the fourth quarter of fiscal2003 that2005, which was paid on November10, 20038, 2005 to holders of record on November3, 2003.1, 2005. This quarterly distribution includes incentive distributions payable to the General Partner to the extent the quarterly distribution exceeds $0.55 per Common Unit.F-124. ADOPTION OF NEW ACCOUNTING STANDARD Effective September 30, 2001, the beginning
5. Selected Balance Sheet Information Inventories consist of the
Partnership's 2002 fiscalfollowing:
September 24,
2005September 25,
2004Propane and refined fuels $ 66,383 $ 50,286 Natural gas 3,267 2,003 Appliances and related parts 10,915 11,852 $ 80,565 $ 64,141 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
Partnership elected to early adopt the provisionsdate ofSFAS 142 which modifies the financial accountingdelivery.Property, plant and
reporting for goodwill and other intangible assets, including the requirement that goodwill and certain intangible assets no longer be amortized. This new standard also requires a transitional impairment review for goodwill, as well as an annual impairment review, to be performed on a reporting unit basis. As a resultequipment consist of theadoption of SFAS 142, amortizationfollowing:
September 24,
2005September 25,
2004Land and improvements $ 31,698 $ 30,811 Buildings and improvements 76,746 77,119 Transportation equipment 40,257 43,529 Storage facilities 81,333 82,665 Equipment, primarily tanks and cylinders 436,918 424,174 Computer software 27,083 21,224 Construction in progress 9,954 10,088 703,989 689,610 Less: accumulated depreciation 304,004 282,908 399,985 406,702 Depreciation expense for the years ended September 24, 2005, September 25, 2004 and September 27, 2003 amounted to $32,865, $33,344 and $27,097, respectively. Depreciation expense for the year ended September
28, 2002 decreased by $7,416 compared24, 2005 included a non-cash charge of $425 related to an impairment of assets as a result of a realignment of the Partnership’s field operations in the fourth quarter of fiscal 2005 (see Note 7). Depreciation expense for the year ended September29, 2001 due to the lack25, 2004 included a non-cash charge ofamortization expense$1,000 related togoodwill. Aside from this change in accounting for goodwill, no other change in accounting for intangiblea write-down of assetswas requiredabandoned as a result of facility integration efforts in theadoptionPartnership’s northeast operations following the Agway Acquisition. As ofSFAS 142 based onSeptember 24, 2005, thenaturePartnership had approximately $5,099 of assets held for sale which were included in property, plant and equipment and are being actively marketed.
6. Goodwill and Other Intangible Assets Goodwill represents the excess of the
Partnership's intangible assets.purchase price over the fair value of net assets acquired. In accordance with SFAS No. 142, ‘‘Goodwill and Other Intangible Assets’’ (‘‘SFAS 142’’), goodwill is not amortized to expense. Rather, 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. As a result of thePartnership completed itsestimated discounted cash flows in the annual impairment review,and,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 2004, as a result of continued losses in one of thefair values of identifiedPartnership’s reporting unitsexceededacquired in fiscal 1999, therespectivecarryingvalues,value of goodwill wasnotconsidered to be fully impairedaswhen applying the discounted cash flow valuation analysis. Accordingly, the Partnership recorded a non-cash charge ofSeptember 27, 2003 nor as$3,177 within the consolidated statement ofSeptember 28, 2002. The following table reflects the effect of the adoption of SFAS 142 on net income and net income per Common Unit as if SFAS 142 had been in effectoperations related to goodwill impairment for theperiods presented:year ended September 25, 2004.
September 27, September 28, September 29, 2003 2002 2001 ------------- ------------- ------------- Net income:As reported $ 48,669 $ 53,524 $ 53,510 Goodwill amortization - - 7,416 ------------- ------------- ------------- As adjusted $ 48,669 $ 53,524 $ 60,926 ============= ============= ============= Basic net income per Common Unit: As reported $ 1.87 $ 2.12 $ 2.14 Goodwill amortization - - 0.29 ------------- ------------- ------------- As adjusted $ 1.87 $ 2.12 $ 2.43 ============= ============= ============= Diluted net income per Common Unit: As reported $ 1.86 $ 2.12 $ 2.14 Goodwill amortization - - 0.29 ------------- ------------- ------------- As adjusted $ 1.86 $ 2.12 $ 2.43 ============= ============= =============The changes in the carrying amount of goodwill for the year ended September 24, 2005 are as follows:
Propane Fuel Oil and
Refined
FuelsNatural Gas
and
ElectricityHVAC All Other Total Balance as of September 27, 2003 $ 240,059 $ — $ — $ — $ 3,177 $ 243,236 Acquired goodwill 22,500 10,900 7,900 656 — 41,956 Goodwill impairment charge recognized (3,177 ) (3,177 ) Balance as of September 25, 2004 $ 262,559 $ 10,900 $ 7,900 $ 656 $ — $ 282,015 Goodwill impairment charge recognized — — — (656 ) — (656 ) Balance as of September 24, 2005 $ 262,559 $ 10,900 $ 7,900 $ — $ — $ 281,359 Other intangible assets,
at September 27, 2003 and September 28, 2002the majority of which were acquired in the Agway Acquisition, consistprimarily of non-compete agreements with a gross carrying amount of $3,608 and $4,240, respectively, and accumulated amortization of $2,573 and $2,766, respectively. These non-compete agreements are amortized under the straight-line method over the periodsof theagreements, ending periodically between fiscal years 2004 and 2011.following:
September 24,
2005September 25,
2004Customer lists $ 19,866 $ 19,866 Tradenames 2,531 3,513 Non-compete agreements 4,956 5,467 Other 1,967 1,967 29,320 30,813 Less: accumulated amortization 8,635 5,231 $ 20,685 $ 25,582 Aggregate amortization expense related to other intangible assets for the years ended September 24, 2005, September 25, 2004 and September 27, 2003 was $4,897, $3,399 and $423, respectively. Amortization expense for the year ended September
28, 2002 and September 29, 2001 was $423, $498 and $563, respectively.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 September27, 200324, 2005 is as follows:2004 - $352; 2005 - $299;2006- $228;– $2,587; 2007- $76– $2,036; 2008 – $1,999, 2009 – $1,995 and2008 - $40. F-132010-$1,965.
7. Restructuring Costs For the year ended September
27, 2003,24, 2005, the Partnership recorded a restructuring charge of $2,775 within the consolidated statements of operations related primarily to employee termination costs incurred as a result of actions taken during fiscal 2005. Specifically, during the fourth quarter of fiscal 2005 the Partnership approved and initiated a plan of reorganization to realign the field operations in an effort to streamline the operating footprint and leverage the system infrastructure to achieve additional operational efficiencies and reduce costs. As a result of this field realignment, the Partnership recorded a restructuring charge of $2,150 during the fourth quarter of fiscal 2005 associated with severance and other employee benefits for approximately 85 positions eliminated under the plan.During fiscal 2004, in connection with the initial integration of certain management and back office functions of Agway Energy, the Partnership’s management approved and initiated plans to restructure the operations of both the Partnership and Agway Energy. Restructuring charges of $2,942 related to plans that had an impact on the assets, employees and operations of the Partnership were recorded in the statement of operations for fiscal 2004 when specific decisions were approved and costs associated with such activities were incurred. Severance and other restructuring or relocation costs associated with assets, employees and operations of Agway Energy in the amount of $2,225 were recorded as liabilities assumed in the purchase business combination and resulted in an increase to goodwill (see Note 3).
The components of remaining restructuring charges are as follows:
Reserve at
September 25,
2004Charges
Through
September 24,
2005Utilization
Through
September 24,
2005Reserve at
September 24,
2005Charges expensed: Severance and other employee costs $ 715 $ 2,625 $ (1,669 ) $ 1,671 Other exit costs — 150 — 150 Total $ 715 $ 2,775 $ (1,669 ) $ 1,821 Charges recorded in purchase accounting: Severance and other employee costs $ 139 $ — $ (139 ) $ — Relocation costs 235 — (116 ) 119 Other exit costs 1,000 — (699 ) 301 Total $ 1,374 $ — $ (954 ) $ 420 The $2,241 in restructuring and other exit costs as of September 24, 2005 is expected to be paid over the course of the next twelve months.
8. Income Taxes
For federal income tax purposes, as well as for state income tax purposes in the majority of the states in which the Partnership operates, the earnings attributable to the Partnership and the Operating Partnership are not subject to corporate level income tax. Rather, the taxable income or loss, which may vary substantially from the net
carrying amountincome or net loss reported by the Partnership in the consolidated statement ofgoodwill decreased by $24operations, is 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 tax attributes 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 other 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.The income tax provision/(benefit) of the Partnership consists of the following:
September 24,
2005September 25,
2004September 27,
2003Current Federal $ (6 ) $ (302 ) $ 10 State and local 809 305 192 Deferred — — — $ 803 $ 3 $ 202 The federal income tax benefits reported for fiscal 2005 and 2004 result from a refund of prior taxes paid.
The provision for income taxes differs from income taxes computed at the United States federal statutory rate as a result of the
salefollowing:
September 24,
2005September 25,
2004September 27,
2003Income tax provision at federal statutory tax rate $ (2,546 ) $ 19,006 $ 17,105 Impact of Partnership income not subject to federal income taxes (10,710 ) (27,477 ) (20,221 ) Permanent differences (1,632 ) 1,135 — Change in valuation allowance 14,888 7,336 3,362 State income taxes 809 305 192 Other, net (6 ) (302 ) (236 ) Provision for income taxes $ 803 $ 3 $ 202 The components of
certainnet deferred taxes and the related valuation allowance as of September 24, 2005 and September 25, 2004 using current enacted tax rates are as follows:
September 24,
2005September 25,
2004Deferred tax assets: Net operating loss carryforwards $ 45,524 $ 30,409 Allowance for doubtful accounts 1,946 1,097 Inventory 531 860 Amortization of intangible assets 557 531 Depreciation 48 — Derivative instruments 1,777 301 Severance and other exit costs 375 473 Other accruals 740 1,301 Total deferred tax assets 51,498 34,972 Deferred tax liabilities: Depreciation — 261 Total deferred tax liabilities — 261 Net deferred tax assets 51,498 34,711 Valuation allowance (51,498 ) (34,711 ) Net deferred tax assets $ — $ — In order to fully realize the net deferred tax assets,
duringtheperiod. 5. SELECTED BALANCE SHEET INFORMATION Inventories consistCorporate 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 thefollowing: September 27, September 28, 2003 2002 --------------------- -------------------- Propane $ 34,033 $ 28,799 Appliances 7,477 7,568 --------------------- -------------------- $ 41,510 $ 36,367 ===================== ==================== The Partnership enters into contracts to buy propane for supply purposes. Such contracts generally have one year terms subject to annual renewal, with propane costs based on market prices atdeferred tax assets will not be realized. Based upon thedatelevel ofdelivery. Property, plantcurrent taxable income andequipment consistprojections of future taxable income of thefollowing:
September 27, September 28, 2003 2002 --------------------- --------------------Land and improvements $ 27,134 $ 28,043 Buildings and improvements 59,543 57,245 Transportation equipment 36,677 46,192 Storage facilities 59,554 59,069 Equipment, primarily tanks and cylinders 370,494 362,001 Computer software 12,122 3,806 Construction in progress 2,531 11,935 --------------------- -------------------- 568,055 568,291 Less: accumulated depreciation 255,265 237,282 --------------------- -------------------- $ 312,790 $ 331,009 ===================== ====================Depreciation expenseCorporate 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 24, 2005 and September 25, 2004. Of the total valuation allowance as of September 24, 2005, $21,519 was established through purchase accounting for theyears endedAgway 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 recorded as a reduction of goodwill with no impact on the deferred tax provision.As of September
27, 2003, September 28, 200224, 2005, the Partnership had tax loss carryforwards for federal income tax reporting purposes of approximately $124,639 which are available to offset future federal taxable income andSeptember 29, 2001 amounted to $27,097, $27,857expire between 2011 and$28,517, respectively. 6. LONG-TERM BORROWINGS Long-term2025.9. Short-Term and Long-Term Borrowings
Short-term and long-term borrowings consist of the following:
F-14
September 24,
2005September 25,
2004Senior Notes, 6.875%, due December 15, 2013, net of unamortized discount of $1,930 $ 423,070 $ 175,000 Term Loan, 6.29% to 7.16%, due March 31, 2010 125,000 — Senior Notes, 7.54%, redeemed March 31, 2005 — 297,500 Senior Notes, 7.37%, redeemed March 31, 2005 — 42,500 Note payable , 8%, due in annual installments through 2006 475 915 Short-term borrowings under Revolving Credit Agreement 26,750 — 575,295 515,915 Less: current portion 27,225 42,940 $ 548,070 $ 472,975 On March 31, 2005, the Partnership completed a refinancing (the ‘‘Refinancing’’) of all of the outstanding principal amount of the Operating Partnership’s 1996 Senior Notes and the 2002 Senior Notes (as defined below). Under the Refinancing, the Partnership issued $250,000 of additional notes under the indenture governing the 2003 Senior Notes (see below) and received proceeds of approximately $246,875, net of a $2,047 discount on sale and related underwriter fees. In addition, the Operating Partnership entered into an amendment to its Revolving Credit Agreement (see below) to provide, among other things, for a five-year $125,000 term loan facility (the ‘‘Term Loan’’). The total net proceeds of approximately $371,875 from the Refinancing, together with cash of approximately $7,335, were used to prepay $297,500 outstanding principal amount of 1996 Senior Notes and $42,500 outstanding principal amount of 2002 Senior Notes (collectively, the ‘‘Redeemed Notes’’), including a prepayment premium of approximately $31,980, interest accrued on the Redeemed Notes of approximately $6,391 from the last interest payment date through the date of redemption and related costs associated with the Refinancing.
The Redeemed Notes required an annual principal repayment of $42,500 through 2012. The Refinancing replaced the annual cash requirement for principal amortization with the $125,000 five-year Term Loan due 2010 and the $250,000 of senior notes due 2013 issued under the indenture governing the 2003 Senior Notes, significantly extending the Partnership’s debt maturities and eliminating refinancing risk associated with the amortization of the Redeemed Notes. The Refinancing is expected to reduce the Partnership’s annual interest expense for at least the next five years. The Partnership recorded a one-time charge of approximately $36,242 for the year ended September 24, 2005 as a result of the Refinancing to reflect the loss on debt extinguishment associated with the prepayment premium and the write-off of $4,262 of unamortized bond issuance costs associated with retirement of the Redeemed Notes.
On December 23, 2003, the Partnership and its subsidiary Suburban Energy Finance Corporation issued $175,000 aggregate principal amount of Senior Notes (the ‘‘2003 Senior Notes’’) with an annual interest rate of 6.875%. On March 31, 2005, in conjunction with the Refinancing, the Partnership and Suburban Energy Finance Corporation issued $250,000 additional senior notes under the indenture governing the 2003 Senior Notes through a debt offering under Rule 144A and Regulation S of the Securities Act of 1933. On September 23, 2005, pursuant to a registration rights agreement, the Partnership exchanged the $250,000 senior notes that were issued on March 31, 2005 in the Refinancing with $250,000 senior notes that were registered with the SEC. 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 senior debt and other liabilities of the Operating Partnership. The 2003 Senior Notes mature on December 15, 2013, and require semi-annual interest payments that began on June 15, 2004. 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 indenture governing the 2003 Senior Notes, the Partnership must offer to repurchase the
September 27, September 28, 2003 2002 --------------------- --------------------Senior Notes, 7.54%, due June 30, 2011 $ 340,000 $ 382,500 Senior Notes, 7.37%, due June 30, 2012 42,500 42,500 Note payable, 8%, due in annual installments through 2006 1,322 1,698 Amounts outstanding under Acquisition Facility of Revolving Credit Agreement - 46,000 Other long-term liabilities 4 71 --------------------- -------------------- 383,826 472,769 Less: current portion 42,911 88,939 --------------------- -------------------- $ 340,915 $ 383,830 ===================== ====================notes at 101% of the principal amount repurchased, if the holders of the notes exercise the right of repurchase. The 2003 Senior Notes contain certain restrictions applicable to the Partnership and certain of its subsidiaries with respect to (i) the incurrence of additional indebtedness; and, (ii) liens, investments, guarantees, loans, advances, payments, mergers, consolidations, distributions, sales of assets and other transactions.
On March 5, 1996, pursuant to a
Senior Note Agreement (the "1996 Senior Note Agreement")senior note agreement, the Operating Partnership issued $425,000 of Senior Notes (the"1996‘‘1996 SeniorNotes"Notes’’) with an annual interest rate of 7.54%. TheOperating Partnership's obligations under the 1996 Senior Note Agreement are unsecured and rank on an equal and ratable basis with the Operating Partnership's obligations under the 2002 Senior Note Agreement and the Revolving Credit Agreement discussed below. The1996 Senior Noteswillwere scheduled to mature June 30, 2011,and require semiannualrequired semi-annual interest paymentswhich commenced June 30, 1996. Theand obligated the Operating Partnership to repay the principal on the 1996 SeniorNote Agreement requires that the principal be paidNotes in equal annualpaymentsinstallments of $42,500startingwhich started on July 1, 2002.Pursuant toThe first annual principal payment was refinanced on July 1, 2002 and thePartnership's intentionsecond and third annual principal payments were made on July 1, 2003 and 2004. The remaining outstanding principal amount of the 1996 Senior Notes of $297,500 was redeemed in full on March 31, 2005. On July 1, 2002, the Operating Partnership received $42,500 from the issuance of 7.37% Senior Notes due June 30, 2012 (the ‘‘2002 Senior Notes’’) in order to refinance the first annual principal payment of $42,500 under the 1996 Senior Notes. The 2002 Senior Notes were redeemed in full on March 31, 2005.On October 20, 2004, the Operating Partnership executed
on April 19, 2002 a Note Purchasethe Third Amended and Restated Credit Agreementfor the private placement of 10-year 7.37% Senior Notes due June 30, 2012(the"2002 Senior Note Agreement"). On July 1, 2002, the Partnership received $42,500 from the issuance of the Senior Notes under the 2002 Senior Note Agreement and used the funds to pay the first annual principal payment of $42,500 due under the 1996 Senior Note Agreement. The Operating Partnership's obligations under the 2002 Senior Note Agreement are unsecured and rank on an equal and ratable basis with the Operating Partnership's obligations under the 1996 Senior Note Agreement and the‘‘Revolving CreditAgreement. Rather than refinance the second annual principal payment of $42,500 due under the 1996 Senior Note Agreement, the Partnership elected to repay this principal payment on June 30, 2003. The Partnership's previous Revolving Credit Agreement, which provided a $75,000 working capital facility and a $50,000 acquisition facility, was scheduled to mature on May 31, 2003. On May 8, 2003, the Partnership completedAgreement’’), replacing the Second Amended and Restated Credit Agreement(the "Revolving Credit Agreement")whichextendswould have expired in May 2006. On March 31, 2005 in conjunction with thepreviousRefinancing, the Operating Partnership executed the first amendment to the Revolving Credit Agreementuntil Mayto provide, among other things, for the Term Loan due March 31,2006.2010. The Revolving Credit Agreement,providesas amended, was scheduled to expire on October 20, 2008 and in addition to the Term Loan provided available credit of $150,000 in the form of a $75,000 revolving working capital facility and a separate $75,000 letter of credit facility. On August 26, 2005, the Partnership completed the second amendment to the Revolving Credit Agreement which, among other things, extended the maturity date to March 31, 2010 to coincide with the maturity of the Term Loan, eliminated the stand-alone $75,000 letter of credit facility and combined that credit with the existing revolving working capital facility and increased the available revolving borrowing capacity by anacquisitionadditional $25,000, thereby raising the amount of the working capital facility to $175,000 (including the $75,000 from the former stand-alone letter of$25,000.credit facility). The increased borrowing capacity will provide additional financial flexibility to support the Partnership’s growth strategies, particularly in the current high commodity price environment. All other terms and conditions under the Revolving Credit Agreement remained the same.Borrowings under the Revolving Credit Agreement, including the Term Loan, bear interest at a rate based upon either LIBOR
plus a margin,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.375%0.375% to.50%0.50%, based upon certain financial tests, is payable quarterly whether or not borrowings occur.These terms are substantially the same as the termsAs of September 24, 2005, there was $26,750 outstanding under theprevious Revolving Credit Agreement. In connection with the completionworking capital facility of the Revolving Credit Agreement that was used to fund working capital requirements.In connection with the Term Loan, the Operating Partnership
repaid $21,000also entered into an interest rate swap contract with a notional amount ofoutstanding borrowings under$125,000 with the issuing lender. 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 CreditAgreement. On June 19, 2003, the Partnership repaid the remaining outstanding balanceAgreement, is not included in, and will be paid in addition to this fixed interest rate of$25,000 under the Revolving Credit Agreement. As of September 27, 2003 there were no borrowings outstanding under the Revolving Credit Agreement. As of September 28, 2002, $46,000 was outstanding under the acquisition facility4.66%. The fair value of thepreviousinterest rate swap amounted to $1,293 at September 24, 2005 and is included in other liabilities with a corresponding amount included within OCI.The Revolving Credit Agreement and
there were no borrowings undertheworking capital facility. As of September 27,2003the Partnership had borrowing capacity of $75,000 under the working capital facility and $25,000 under the acquisition facility of the Revolving Credit Agreement. The weighted average interest rate associated with borrowings under the Revolving Credit Agreement was 3.42%, 3.67% and 6.98% for fiscal 2003, 2002 and 2001, respectively. F-15The 1996SeniorNote Agreement, the 2002 Senior Note Agreement and the Revolving Credit AgreementNotes both contain various restrictive and affirmative covenants applicable to the OperatingPartnership;Partnership and the Partnership, respectively, including(a) maintenance of certain financial tests, including, but not limited to, a leverage ratio less than 5.0 to 1 and an interest coverage ratio in excess of 2.50 to 1, (b)(i) restrictions on the incurrence of additional indebtedness, and(c)(ii) restrictions on certain liens, investments, guarantees, loans, advances, payments, mergers, consolidations, distributions, sales of assets and other transactions.During December 2002,As a result of the Refinancing, the Partnershipamendedeliminated the1996 Senior Note Agreementrequirement to(i) eliminatemaintain a leverage ratio and anadjusted net worth financial test to be consistentinterest coverage ratio associated with the2002Redeemed Notes withoutadding comparable financial covenants under the 2003 Senior
Note Agreement andNotes. Under the Revolving Credit Agreement,and (ii) requirethe Operating Partnership is required to maintain a leverage ratio of less than5.254.0 to 1. In addition, the Operating Partnership is required to maintain an interest coverage ratio of greater than 2.5 to 1when the underfunded portion of the Partnership's pension obligations is used in the computation of the ratio.on a consolidated basis. The Partnershipwasand the Operating Partnership were in compliance with all covenants and terms of the19962003 SeniorNote Agreement, the 2002 Senior Note AgreementNotes and the Revolving Credit Agreement as of September27, 2003.24, 2005.Debt origination costs representing the costs incurred in connection with the placement of, and the subsequent amendment to, the
Partnership'sPartnership’s Senior Notes and 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 September27, 200324, 2005 and September28, 200225, 2004 include debt origination costs with a net carrying amount of$5,960$8,848 and$5,926,$10,506, respectively. Aggregate amortization expense related to deferred debt origination costs included within interest expense for the years ended September 24, 2005, September 25, 2004 and September 27, 2003September 28, 2002was $1,514, $1,421 andSeptember 29, 2001 was$1,291,$1,338 and $2,006,respectively.The aggregate amounts of long-term debt maturities subsequent to September
27, 200324, 2005 are as follows:2004 - $42,911; 2005 - $42,940;2006- $42,975;– $27,225; 2007- $42,500;– $0; 2008- $42,500;– $0; 2009 – $0; and,thereafter - $170,000. F-167. RESTRICTED UNIT PLANSthereafter-$548,070.10. Restricted Unit Plans
In November 2000, the Partnership adopted the Suburban Propane Partners, L.P. 2000 Restricted Unit Plan (the
"2000‘‘2000 Restricted UnitPlan"Plan’’) which authorizes the issuance of Common Units with an aggregate value of $10,000 (487,804 Common Units valued at the initial public offering price of $20.50 per unit) to executives, managers and other employees of the Partnership. 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 issuance date and the remaining 50% of the Common Units vesting at the end of the fifth anniversary of the issuance 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 at the date of grant. Restricted Units are subject to forfeiture in certain circumstances as defined in the 2000 Restricted Unit Plan.Following is a summary of activity in the 2000 Restricted Unit Plan:
Units Weighted Average
Grant Date
Fair Value Per UnitOutstanding September 28, 2002 111,986 $ 24.19 Awarded 44,288 27.74 Forfeited (5,726 ) (20.66 ) Outstanding September 27, 2003 150,548 $ 25.37 Awarded 115,730 30.64 Forfeited (27,560 ) (25.46 ) Issued (10,605 ) (20.66 ) Outstanding September 25, 2004 228,113 $ 28.25 Awarded 94,239 33.20 Forfeited (26,282 ) (30.92 ) Issued (22,292 ) (24.77 ) Outstanding September 24, 2005 273,778 $ 29.17 During the years ended September 24, 2005, September 25, 2004 and September 27, 2003, the Partnership amortized $1,806, $1,171 and $863, respectively, of unearned compensation associated with the 2000 Restricted Unit Plan, net of forfeitures.
11. Compensation Deferral Plan
In 1996, the Partnership adopted the 1996 Restricted Unit Award Plan (the
"1996‘‘1996 Restricted UnitPlan"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 Elected 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 ina new compensation deferral plan ofthePartnership and the Operating Partnership (see Note 8,Compensation DeferralPlan). Following is a summary of activity in the Restricted Unit Plans:
Weighted Average Grant Date Fair Units Value Per Unit ------------------ -----------------------OUTSTANDING SEPTEMBER 29, 2001 48,960 $ 20.66 Awarded 66,298 26.63 Forfeited (3,272) (20.66) ------------------ ----------------------- OUTSTANDING SEPTEMBER 28, 2002 111,986 24.19 Awarded 44,288 27.74 Forfeited (5,726) (20.66) ------------------ ----------------------- OUTSTANDING SEPTEMBER 27, 2003 150,548 $ 25.37 ================== =======================During the years ended September 27, 2003, September 28, 2002 and September 29, 2001, the Partnership amortized $863, $603 and $228, respectively, of unearned compensation associated with the 2000 Restricted Unit Plan, net of forfeitures. 8. COMPENSATION DEFERRAL PLANPlan.Effective May 26, 1999, in connection with the
Partnership'sPartnership’s Recapitalization, the Partnership adopted the Compensation Deferral Plan (the"Deferral Plan"‘‘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.The Deferral Plan also allows eligible employees to defer receipt of Common Units subsequently granted by the Partnership under the Deferral Plan. The Partnership granted Common Units under the Deferral Plan only once during fiscal 2000. The Common Units granted under the Deferral Plan and related Partnership distributions were subject to forfeiture provisions such that (a) 100% of the Common Units would be forfeited if the grantee ceased to be F-17employed prior to the third anniversary of the Recapitalization, (b) 75% would be forfeited if the grantee ceased to be employed after the third anniversary but prior to the fourth anniversary of the Recapitalization and (c) 50% would be forfeited if the grantee ceased to be employed after the fourth anniversary but prior to the fifth anniversary of the Recapitalization. All forfeiture provisions lapsed in August of 2002. Upon issuance of Common Units under the Deferral Plan, unearned compensation equivalent to the market value of the Common Units at the date of grant is recorded. The unearned compensation is amortized in accordance with the Deferral Plan's forfeiture provisions. The unamortized unearned compensation value is shown as a reduction of partners' capital in the accompanying consolidated balance sheets.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 management 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 the members of the General Partner and
may now be voted and/orare freely traded. Certain members of management elected to further defer receipt of their deferred units (totaling 299,511 Common Units) until January 2008. During fiscal 2005, 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. During fiscal 2004, 5,310 Common Units were deposited into the Deferral Plan and 7,490 Common Units were distributed out of the Deferral Plan, resulting in a net reduction of $17 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
27, 200324, 2005 and September28, 2002,25, 2004, there were299,511300,603 and596,821297,331 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 liability in the amount of$5,795$5,887 and$11,567$5,778 as of September27, 200324, 2005 and September28, 2002,25, 2004, respectively, are reflected in the accompanyingcondensedconsolidated balance sheets as components ofpartners'partners’ capital.DuringOn November 2, 2005, thesecond quarter of fiscal 2003, the Partnership recorded a $5,772 reduction in the deferred compensation liability and a corresponding reduction in the valueDeferral Plan was amended to, among other things, disallow any additional deferrals of Common Unitsheld ininto the trustboth within partners' capital, relatedsubsequent to December 31, 2004.12. Employee Benefit Plans
Defined Contribution Plan. The Partnership has a defined contribution plan covering most employees. Employer contributions and costs are a percent of the participating employees’ compensation, subject to the
valueachievement ofCommon Units distributed fromannual performance targets of thetrust. 9. PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS DEFINED BENEFIT PLAN.Partnership. These contributions totaled $183, $1,261 and $1,305 for the years ended September 24, 2005, September 25, 2004 and September 27, 2003, respectively.Pension Benefits and Retiree Health and Life Benefits.
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 for a cash balance format as compared to a final average pay format which was in effect prior to January 1, 1998. The cash balance format is designed to evenly spread the growth of a
participant'sparticipant’s earned retirement benefit throughout his/her career as compared to the final average pay format, under which a greater portion of employee benefits were earned toward the latter stages ofone'sone’s career. Effective January 1, 2000, participation in the noncontributory defined benefit pension plan waslimited 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 will now receive interest credits only toward their ultimate retirement benefit.
Contributions, as needed, are made to a trust maintained by the Partnership. The
trust'strust’s assets consist primarily ofcommon stock,domestic and international mutual funds, as well as fixed incomesecurities and real estate.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 fiscal2003, 20022005, 2004 or2001.2003. Recently, there has been increased scrutiny over cash balance defined benefit pension plans and resulting litigation regarding such plans sponsored by other companies. These developments may result in legislative changes impacting cash balance defined benefit pension plans in the future. While no such legislative changes have been adopted, and if adopted the impact on thePartnership'sPartnership’s defined benefit pension plan is not certain, there can be no assurances that future legislative developments will not have an adverse effect on thePartnership'sPartnership’s results of operations or cash flows.F-18DEFINED CONTRIBUTION PLAN. The Partnership has a defined contribution plan covering most employees. Employer contributionsRetiree Health and
costs are a percent of the participating employees' compensation, subject to the achievement of annual performance targets of the Partnership. These contributions totaled $1,305, $947 and $4,560 for the years ended September 27, 2003, September 28, 2002 and September 29, 2001, respectively. POSTRETIREMENT BENEFITS OTHER THAN PENSIONS.Life Benefits. The Partnership provides postretirement health care and life insurance benefits for certain retired employees. Partnership employees hired prior to July 1993 and that 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 to receive benefits under the postretirement plan subsequent to March 1, 1998, were provided a settlement by increasing their accumulated benefits under the cash balance pension plan noted above. ThePartnership does not fund itsPartnership’s postretirement health care and life insurance benefitplans.plans are unfunded.Projected Benefit Obligation, Fair Value of Plan Assets and Funded Status. The following
table providestables provide a reconciliation of the changes in the benefit obligations and the fair value of the plan assets for each of the years ended September27, 200324, 2005 and September28, 200225, 2004 and a statement of the funded status for bothyears:years using an end of year measurement date:
Other Pension Benefits Postretirement Benefits --------------------------------------- ------------------------------------- 2003 2002 2003 2002 ------------------ ------------------ ------------------ ---------------- RECONCILIATION OF BENEFIT OBLIGATIONS:Benefit obligation at beginning of year $ 174,698 $ 167,187 $ 41,136 $ 37,559 Service cost 629 4,445 17 16 Interest cost 11,376 11,581 2,641 2,574 Actuarial loss/(gain) 4,066 8,700 (4,115) 3,852 Curtailment gain - (1,812) - - Benefits paid (16,593) (15,403) (2,497) (2,865) -------------- ------------------ ------------------ ---------------- Benefit obligation at end of year $ 174,176 $ 174,698 $ 37,182 $ 41,136 ============== ================== ================== ================ RECONCILIATION OF FAIR VALUE OF PLAN ASSETS: Fair value of plan assets at beginning of year $ 121,534 $ 143,116 $ - $ - Actual return on plan assets 17,099 (6,179) - - Employer contributions 10,000 - 2,497 2,865 Benefits paid (16,593) (15,403) (2,497) (2,865) -------------- ------------------ ------------------ ---------------- Fair value of plan assets at end of year $ 132,040 $ 121,534 $ - $ - ============== ================== ================== ================ FUNDED STATUS: Funded status at end of year $ (42,136) $ (53,164) $ (37,182) $ (41,136) Unrecognized prior service cost - - (2,306) (3,026) Net unrecognized actuarial losses 80,139 85,077 3,603 8,060 Accumulated other comprehensive (loss) (80,139) (85,077) - - -------------- ------------------ ------------------ ---------------- Accrued benefit liability (42,136) (53,164) (35,885) (36,102) Less: Current portion - - 2,450 2,818 -------------- ------------------ ------------------ ---------------- Non-current benefit liability $ (42,136) $ (53,164) $ (33,435) $ (33,284) ============== ================== ================== ================
Pension Benefits Retiree Health and Life
Benefits2005 2004 2005 2004 Reconciliation of benefit obligations: Benefit obligation at beginning of year $ 177,056 $ 174,176 $ 35,506 $ 37,182 Service cost — — 18 18 Interest cost 9,107 9,765 1,783 2,138 Actuarial loss/(gain) 12,025 13,415 (1,377 ) (956 ) Settlement payments (8,251 ) (12,288 ) — — Benefits paid (7,858 ) (8,012 ) (2,257 ) (2,876 ) Benefit obligation at end of year $ 182,079 $ 177,056 $ 33,673 $ 35,506 Reconciliation of fair value of plan assets: Fair value of plan assets at beginning of year $ 142,021 $ 132,040 $ — $ — Actual return on plan assets 15,961 15,181 — — Employer contributions — 15,100 2,257 2,876 Settlement payments (8,251 ) (12,288 ) — — Benefits paid (7,858 ) (8,012 ) (2,257 ) (2,876 ) Fair value of plan assets at end of year $ 141,873 $ 142,021 $ — $ —
Pension Benefits Retiree Health and Life
Benefits2005 2004 2005 2004 Reconciliation of benefit obligations: Funded status: Funded status at end of year $ (40,206 ) $ (35,035 ) $ (33,673 ) $ (35,506 ) Unrecognized prior service cost — — (865 ) (1,585 ) Net unrecognized actuarial losses 75,656 76,898 1,269 2,646 Net amount recognized at end of year $ 35,450 $ 41,863 $ (33,269 ) $ (34,445 ) Amounts recognized in consolidated balance sheets consist of: Prepaid benefit cost $ — $ — $ — $ — Accrued benefit liability (40,206 ) (35,035 ) (33,269 ) (34,445 ) Accumulated other comprehensive (loss) 75,656 76,898 — — Net amount recognized at end of year $ 35,450 $ 41,863 (33,269 ) (34,445 ) Less: Current portion 2,211 2,829 Non-current benefit liability $ (31,058 ) $ (31,616 ) The
funded statuschange in accumulated other comprehensive (loss) attributable to a favorable movement in the minimum pension liability for the year ended September 24, 2005 was $1,242. During fiscal 2004, lump sum benefit payments to either terminated or retired individuals amounted to $12,288. The lump sum benefit payments exceeded the interest cost component of thePartnership'snet periodic pension cost of $9,765 and, as a result, the Partnership was required to recognize a non-cash settlement charge of $5,337 during the fourth quarter of fiscal 2004, pursuant to SFAS 88 ‘‘Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits.’’ The non-cash charge was required to accelerate recognition of a portion of cumulative unrecognized losses in the defined benefit pensionplan continuesplan. These unrecognized losses were previously accumulated as a reduction tobe impacted by the turbulentpartners’ capitalmarkets affecting the market value(cumulative reduction ofour pension asset portfolio and by the low interest rate environment affecting the actuarial value$80,139 as of theprojected benefit obligations. In an effortend of the 2003 fiscal year) and were being amortized tominimize future increasesexpense as part of the Partnership’s net periodic pension cost inthe pension plan F-19benefit obligations, theaccordance with SFAS 87 ‘‘Employers’ Accounting for Pensions.’’The Partnership
adopted an amendmentmade voluntary contributions of $15,100 and $10,000 to the defined benefit pension planwhich ceased future service credits effective January 1, 2003. This amendment resulted in a curtailment gain of $1,093 included within the net periodic pension cost for the year ended September 28, 2002. Additionally,during fiscal 2004 and 2003,the Partnership made a voluntary contribution of $10,000 to the plan,respectively, thereby taking proactive steps to improve the funded status of the plan and reduce the minimum pension liability.Plan Asset Allocation. The following table presents the allocation of assets held in trust:
September 24, 2005
Actual AllocationSeptember 25, 2004
Actual AllocationCommon stock 42 % 42 % Corporate bonds 0 % 8 % Government bonds 0 % 12 % Mutual funds 55 % 30 % Cash and cash equiva lents 3 % 8 % 100 % 100 % The Partnership’s investment policies and strategies, as set forth in the Investment Management Policy and Guidelines, are monitored by a Benefits Committee comprised of seven members of management. The investment objective related to the defined benefit pension plan assets is to maximize total return with strong emphasis on the preservation of capital. The target asset mix is as follows: (i) the domestic equity portfolio should range between 40% and 60%; (ii) the international equity portfolio should range between 5% and 25%; and, (iii) the fixed income portion of the portfolio should range between 20% and 50%.
Projected Contributions and Benefit Payments. There are no projected minimum funding requirements under the Partnership’s defined benefit pension plan for fiscal 2006. The Partnership estimates that retiree health and life benefit contributions will be $2,959 for fiscal 2006. Estimated future benefit payments for both pension and retiree health and life benefits are as follows:
Fiscal Year Pension
BenefitsRetiree Health
and Life Benefits2006 $ 17,940 $ 2,959 2007 14,695 2,921 2008 14,725 2,868 2009 14,974 2,810 2010 14,838 2,734 2011 through 2015 68,985 12,950 Effect on Operations. The following table provides the components of net periodic
benefitpension costs included in operating expenses for the years ended September27, 200324, 2005, September 25, 2004 and September28, 2002:
Other Pension Benefits Postretirement Benefits ------------------------------------- --------------------------------- 2003 2002 2003 2002 ------------ --------------- --------------- ---------------Service cost $ 629 $ 4,445 $ 17 $ 16 Interest cost 11,376 11,581 2,641 2,574 Expected return on plan assets (12,161) (14,974) - - Amortization of prior service cost - (210) (720) (720) Curtailment gain - (1,093) - - Recognized net actuarial loss 4,066 1,912 342 41 ------------ --------------- --------------- --------------- Net periodic benefit cost $ 3,910 $ 1,661 $ 2,280 $ 1,911 ============ =============== =============== ===============Pension benefit expense was $113 (consisting of service cost of $5,024, interest cost of $11,034, expected return on plan assets of $15,735 and amortization of prior service cost of $210) and other postretirement benefit costs were $2,341 (consisting of service cost of $123, interest cost of $2,794, amortization of prior service cost of $721 and recognized net actuarial loss of $145) for the year ended September 29, 2001.27, 2003:
Pension Benefits Retiree Health and Life Benefits 2005 2004 2003 2005 2004 2003 Service cost $ — $ — $ 629 $ 18 $ 18 $ 17 Interest cost 9,107 9,765 11,376 1,783 2,138 2,641 Expected return on plan assets (9,335 ) (9,848 ) (12,161 ) — — — Amortization of prior service cost — — — (720 ) (720 ) (720 ) Settlement charge — 5,337 — — — — Recognized net actuarial loss 6,641 5,986 4,066 — — 342 Net periodic benefit costs $ 6,413 $ 11,240 $ 3,910 $ 1,081 $ 1,436 $ 2,280 Actuarial Assumptions. The assumptions used in the measurement of the
Partnership'sPartnership’s benefit obligations as of September 24, 2005 and September 25, 2004 are shown in the following table:
Other Pension Benefits Postretirement Benefits ------------------------------------- --------------------------------- September September September September 27, 2003 28, 2002 27, 2003 28, 2002 --------------- ---------------- -------------- ------------Weighted-average discount rate 6.00% 6.75% 6.00% 6.75% Average rate of compensation increase n/a 3.50% - - Weighted-average expected long-term rate of return on plan assets 7.75% 8.50% - -
Pension Benefits Retiree Health and Life
Benefits2005 2004 2005 2004 Weighted-average discount rate 5.25 % 5.50 % 5.25 % 5.25 % Average rate of compensation increase n/a n/a n/a n/a The
followingassumptionswereused in the measurement of periodic pension and postretirement benefit costs for thePartnership's benefit obligations as ofyears ended September29, 2001: weighted-average24, 2005, September 25, 2004 and September 27, 2003 are shown in the following table:
Pension Benefits Retiree Health and Life Benefits 2005 2004 2003 2005 2004 2003 Weighted-average discount rate 5.50 % 6.00 % 6.75 % 5.25 % 6.00 % 6.75 % Average rate of compensation increase n/a n/a n/a n/a n/a n/a Weighted-average expected long-term rate of return on plan assets 7.50 % 7.75 % 8.50 % n/a n/a n/a Health care cost trend n/a n/a n/a 11.00 % 11.50 % 13.00 % The discount rate assumption takes into consideration current market expectations related to long-term interest rates and the projected duration of
7.25%, average ratethe Partnership’s pension obligations based on a benchmark index with similar characteristics as the expected cash flow requirements ofcompensation increase of 3.50% and weighted-average expectedthe Partnership’s defined benefit pension plan over the long-term. The long-term rate of return on plan assetsof 9.50%. The accumulated postretirement benefit obligation was based on a 13% increaseassumption reflects estimated future performance in thecostPartnership’s pension asset portfolio considering the investment mix ofcovered health care benefits at September 27, 2003the pension asset portfolio anda 12% increase in the cost of covered health care benefits at September 28, 2002.historical asset performance.The
13%11.00% increase in health care costs assumed at September27, 200324, 2005 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 thePartnership'sPartnership’s benefit obligation as of September27, 200324, 2005by approximately
$1,354$967 and the aggregate of service and interest components of net periodic postretirement benefit expense for the year ended September27, 200324, 2005 by approximately$105.$60. Decreasing the assumed health care cost trend rates by 1.0% in each year would decrease thePartnership'sPartnership’s benefit obligation as of September27, 200324, 2005 by approximately$1,222$855 and the aggregate of service and interest components of net periodic postretirement benefit expense for the year ended September27, 200324, 2005 by approximately$94. F-2010. FINANCIAL INSTRUMENTS DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES.$54. 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.13. Financial Instruments
Derivative Instruments and Hedging Activities. The Partnership purchases propane and refined fuels at various prices that are eventually sold to its customers, exposing the Partnership to market fluctuations in the price of
propane.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, to protect margins and to ensure supply during periods of high demand. Derivative instruments are used to hedge a portion of thePartnership'sPartnership’s forecasted purchases for no more than one year in the future.SFAS No. 133 "Accounting for Derivative InstrumentsThere were no unrealized gains or losses associated with the Partnership’s commodity price hedging activities included in OCI as of September 24, 2005.For the years ended September 24, 2005, September 25, 2004 and
Hedging Activities," as amended by SFAS No. 137, SFAS No. 138 and SFAS No. 149 ("SFAS 133") requires all derivatives (with certain exceptions), whether designated in hedging relationships or not, to be recorded on the consolidated balance sheet at fair value. SFAS 133 requires that changesSeptember 27, 2003, operating expenses included unrealized losses in thederivative instrument's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges, either fair value hedges or cash flow hedges, allows a derivative's gainsamount of $2,497, $4,523 andlosses to offset related results on the hedged item in the statement of operations, and requires that a company formally document, designate and assess the effectiveness of transactions that receive hedge accounting. Fair value hedges are derivative financial instruments that hedge the exposure$1,500, respectively, attributable to changes in the fair value of derivative instruments not designated as hedges. In connection with the Agway Acquisition, the Partnership acquired certain futures and option contracts that were identified as hedges of future purchases of fuel oil and propane with a fair value of $6,327 which were recorded as derivative assets at fair value in purchase accounting. As the underlying futures and option contracts were settled during fiscal 2004, the derivative assets were charged to cost of products sold as anassetoffset to the realized gains from contract settlement. The impact on cost of products sold represented a non-cash charge resulting from the application of purchase accounting on derivative instruments acquired. For the year ended September 25, 2004, the Partnership recorded a non-cash charge of $6,327 within cost of products sold related to contracts settled during the period.In addition, borrowings under the Term Loan bear interest at a variable rate based upon either LIBOR or
liability orWachovia National Bank's prime rate, plus anidentified portion thereof attributableapplicable margin depending on the level of the Operating Partnership’s total leverage. Therefore, the Partnership is subject toa particular risk. Cash flow hedges are derivative financial instruments that hedgeinterest rate risk on theexposure to variability in expected future cash flows attributable to a particular risk. Sincevariable component of the interest rate. On March 31,2002,2005, thePartnership's futuresPartnership entered into an interest rate swap agreement in order to manage its interest rate risk. The interest rate swap is being accounted for under SFAS 133 andforward contracts qualify and havehas been designated as a cash flowhedges and, as such, the effective portions of changeshedge. Changes in the fair value ofthese derivative instruments are recorded in other comprehensive (loss)/income ("OCI") andthe interest rate swap are recognized incost of products sold whenOCI until the hedged itemimpactsis recognized in earnings. As of September27, 2003,24, 2005, an unrealizedgains on derivative instruments designated as cash flow hedges in the amountloss of$1,129 were$1,293 was included in OCI attributable to the interest rate swap agreement andareis expected to be recognized in earningsduring the next 12 monthsas thehedged forecasted transactions occur.interest on the Term Loan impacts earnings through March 31, 2010. However, due to changes in thevolatility of the commodities market,interest rate environment, the corresponding value in OCI is subject to change prior to its impact on earnings.Option contracts are not classified as hedges and, as such, changes in the fair value of these derivative instruments are recognized within operating expenses in the consolidated statement of operations as they occur. Additionally, prior to March 31, 2002, the Partnership's futures and forward contracts were not designated as cash flow hedges and the changes in fair value of these instruments were recognized in earnings as they occurred. For the year ended September 27, 2003, operating expenses included unrealized losses in the amount of $1,500 compared to unrealized gain in the amount of $5,356 for the year ended September 28, 2002, attributable to changes in the fair value of derivative instruments not designated as hedges. CREDIT RISK.Credit Risk. The
Partnership'sPartnership’s principal customers are residential and commercial end users of propane and refined fuels served by approximately320370 customer service centers in4030 states. No single customer accounted for more than 10% of revenues during fiscal2003, 20022005, 2004 or20012003 and no concentration of receivables exists at the end of fiscal20032005 or2002.2004.Futures contracts are traded on and guaranteed by the New York
MerchantileMercantile Exchange("NYMEX"(‘‘NYMEX’’) and as a result, have minimal credit risk. Futures contracts traded with brokers of the NYMEX require daily cash settlements in margin accounts. The Partnership is subject to credit risk with forward and option contracts entered into with various third parties to the extent the counterparties do not perform. The Partnership evaluates the financial condition of each counterparty with which it conducts business and establishes credit limits to reduce exposure to credit risk based on non-performance. The Partnership does not require collateral to support the contracts.F-21FAIR VALUE OF FINANCIAL INSTRUMENTS.Fair Value of Financial Instruments. The fair value of cash and cash equivalents are 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'sPartnership’s Senior Notes approximates their fair market value.11. COMMITMENTS AND CONTINGENCIES14. Commitments and Contingencies
Commitments. The Partnership leases certain property, plant and equipment, including portions of the
Partnership'sPartnership’s vehicle fleet, for various periods under noncancelable leases. Rental expense under operating leases was$24,337, $24,005$28,559, $27,315 and$23,354$24,337 for the years ended September 24, 2005, September 25, 2004 and September 27, 2003,September 28, 2002 and September 29, 2001,respectively.Future minimum rental commitments under noncancelable operating lease agreements as of September
27, 200324, 2005 are as follows:Fiscal Year
----------- 2004 $ 17,796 2005 12,868 2006 9,959 2007 5,860 2008 and thereafter 6,410 CONTINGENCIES.
2006 $20,295 2007 15,096 2008 10,688 2009 5,856 2010 and thereafter 5,814 Contingencies. As discussed in Note 2, the Partnership is self-insured for general and product,
workers'workers’ compensation and automobile liabilities up to predetermined amounts above which third party insurance applies. At September27, 200324, 2005 and September28, 2002,25, 2004, the Partnership had accrued insurance liabilities of$28,639$46,457 and$26,969,$38,241, 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 thePartnership'sPartnership’s financial position or future results 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 $10,046 and $2,941 as of September 24, 2005 and September 25, 2004, respectively.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"(‘‘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"‘‘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"‘‘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 (‘‘EPA’’) as a potentially responsible party (‘‘PRP’’) under CERCLA and at sites with above ground and underground fuel storage tanks.
With the Agway Acquisition, the Partnership acquired certain properties and assets, including fuel oil tanks and gasoline stations, that are subject to extensive federal, state and local environmental laws and
regulation, including investigation and remediation of contaminated soil and groundwater, transportation of hazardous materials, other environmental protection measures and health and safety matters. Based on a review of certain Phase I Environmental Site Assessments and, at certain sites, groundwater and/or soil sample analysis, the Partnership identified that certain of these properties had either known or probable environmental exposure, some of which are currently in varying stages of investigation, remediation or monitoring. Under the agreement for the Agway Acquisition, the seller was required to deposit $15,000 from the total purchase price into an escrow account to be used to fund remediation costs at the acquired properties. The escrowed funds will be used to fund environmental costs and expenses during the first three years following the closing date of the Agway Acquisition. Subject to amounts withheld with respect to any pending claims made prior to the third anniversary of the closing date of the Agway Acquisition, any remaining escrowed funds will be remitted to the seller at the end of the three-year period.
Based on the Partnership’s best estimate of future costs for environmental investigations, remediation and ongoing monitoring activities associated with acquired properties with either known or probable environmental exposures an environmental reserve in the amount of $13,750 was established in purchase accounting. The Partnership established a corresponding environmental escrow asset in the amount of $13,750 related to the future reimbursement from escrowed funds for environmental spending. As of September 24, 2005 and September 25, 2004, the environmental reserve amounted to $5,768 and $11,500, respectively, and the corresponding environmental escrow asset amounted to $6,151 and $11,500, respectively. The environmental reserves are recorded on an undiscounted basis.
Estimating the extent of the Partnership’s responsibility for a particular site and the method and ultimate cost of remediation of that site requires a number of assumptions and estimates on the part of management. As a result, the ultimate outcome of remediation of the sites may differ from current estimates. As additional information becomes available, estimates will be adjusted as necessary. Based on information currently available, and taking into consideration the level of the environmental reserve and the environmental escrow discussed above, management believes that any liability that may ultimately result from changes in current estimates will not have a material impact on the results of operations, financial position or cash flows of the Partnership.
Future developments, such as stricter environmental, health or safety laws and regulations thereunder, could affect Partnership operations. The Partnership anticipates that compliance with or liabilities under environmental, health and safety laws and regulations, including CERCLA, will not have a material adverse effect on the Partnership. To the extent that there are any environmental liabilities unknown to the Partnership or environmental, health or safety laws or regulations are made more stringent, there can be no assurance that the
Partnership'sPartnership’s results of operations will not be materially and adversely affected.F-2212. GUARANTEES FASB Financial Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for15. Guarantees
Including Indirect Guarantees of Indebtedness of Others," expands the existing disclosure requirements for guarantees and requires recognition of a liability for the fair value of guarantees issued after December 31, 2002.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
2010.2012. 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$14,355.$18,121. Of this amount, the fair value of residual value guarantees for operating leases entered into after December 31, 2002 was$2,067$6,292 and $3,684 as of September 24, 2005 and September 25, 2004, respectively, which is reflected in other liabilities, with a corresponding amount included within other assets, in the accompanying consolidated balancesheet assheets.16. Public Offerings
On December 16, 2003, the Partnership sold 2,600,000 Common Units in a public offering at a price of
September 27, 2003. 13. PUBLIC OFFERINGS$30.90 per Common Unit realizing proceeds of $76,026, net of underwriting commissions and other offering expenses. On December 23, 2003, following the underwriters’ full exercise of their over-allotment option, the Partnership sold an additional 390,000 Common Units at $30.90 per Common Unit, generatingadditional net proceeds of $11,540. The aggregate net proceeds of $87,566 were used to fund a portion of the purchase price for the Agway Acquisition. These transactions increased the total number of Common Units outstanding to 30,256,767. As a result of the Public Offering, the combined General Partner interest in the Partnership was reduced from 1.71% to 1.54% while the Common Unitholder interest in the Partnership increased from 98.29% to 98.46%.
On June 18, 2003, the Partnership sold 2,282,500 Common Units in a public offering at a price of $29.00 per Common Unit realizing proceeds of $62,879, net of underwriting commissions and other offering expenses. On June 26, 2003, following the
underwriters'underwriters’ full exercise of their over-allotment option, the Partnership sold an additional 342,375 Common Units at $29.00 per Common Unit, generating additional net proceeds of $9,307. The aggregate net proceeds of $72,186 were used for general partnership purposes, including working capital and the repayment of outstanding borrowings under the Revolving Credit Agreement and the second annual principal payment of $42,500 due under the 1996 Senior Note Agreement on June 30, 2003. These transactions increased the total number of Common Units outstanding to 27,256,162. As a result of the Public Offering, the combinedgeneral partnerGeneral Partner interest in the Partnership was reduced from 1.89% to 1.71% while the Common Unitholder interest in the Partnership increased from 98.11% to 98.29%.On October 17, 2000, the17. Discontinued Operations and Disposition
The Partnership
sold 2,175,000 Common Units in a public offering at a price of $21.125 per Common Unit realizing proceeds of $43,500, net of underwriting commissions and other offering expenses. On November 14, 2000, following the underwriter's partial exercise ofcontinuously evaluates itsover-allotment option, the Partnership sold an additional 177,700 Common Units at the same price, generating additional net proceeds of $3,600. The aggregate net proceeds of $47,100 were applied to reduce the Partnership's outstanding Revolving Credit Agreement borrowings. These transactions increased the total number of Common Units outstanding to 24,631,287. 14. DISCONTINUED OPERATIONS AND DISPOSITION In line with the Partnership's strategy of divestingexisting operationsin slower growing or non-strategic markets in an effortto 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 fiscal 2004, the Partnership sold 24 customer service centers for net cash proceeds of $39,352. The Partnership recorded a gain on sale of $26,332 during fiscal 2004 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’’). During fiscal 2005, the Partnership finalized certain purchase price adjustments with the buyer of these customer service centers and recorded an additional gain on sale of $976. The individual captions on the consolidated statements of operations for the years ended September 25, 2004 and September 27, 2003 exclude the results from these discontinued operations, which were part of the Partnership’s propane segment.During fiscal 2003, the Partnership sold nine customer service centers,
during fiscal 2003which were part of the Partnership’s propane segment, for net cash proceeds of approximately $7,197. The Partnership recorded a gain on sale ofapproximately$2,483 during fiscal 2003 whichhas beenwas accounted for within discontinued operations pursuant to SFASNo. 144, "Accounting for144.18. Segment Information
The Partnership manages and evaluates its operations in five reportable segments: Propane, Fuel Oil and Refined Fuels, Natural Gas and Electricity, HVAC and All Other. The chief operating decision maker evaluates performance of the
Impairment or Disposaloperating segments using a number ofLong-Lived Assets." Prior period resultsperformance measures, including gross margins and 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 in the consolidated statements of operations. In addition, certain costs associated with field operations support that are reported in operating expenses in the consolidated statements of operations,attributable to these nine customer service centers wereincluding purchasing, training and safety, are notsignificant and, as such, prior period results have not been reclassified to remove financial results from continuing operations. On January 31, 2002, the Partnership sold its 170 million gallon propane storage facility in Hattiesburg, Mississippi, which was considered a non-strategic asset, for net cash proceeds of approximately $7,988, resulting in a gain on sale of approximately $6,768. F-2315. SUBSEQUENT EVENT On November 10, 2003, the Partnership announced that it had entered into an asset purchase agreement (the "Purchase Agreement") to acquire substantially all of the assets of Agway Energy Products, LLC, Agway Energy Services PA, Inc. and Agway Energy Services, Inc. (collectively "Agway Energy"), all of which are wholly owned subsidiaries of Agway, Inc., for total cash consideration of approximately $206,000, subject to certain purchase price adjustments. Agway, Inc. is presently a debtor-in-possession under Chapter 11 of the Bankruptcy Code pending before the United States Bankruptcy Court for the Northern District of New York. Agway Energy is not a Chapter 11 debtor. The Purchase Agreement was filed with the United States Bankruptcy Court and on November 24, 2003, the Bankruptcy Court approved Agway, Inc.'s motion to establish bid procedures for the sale. In addition, the transaction has been approved by the Partnership's Board of Supervisors. Closing on the sale under the Purchase Agreement is subjectallocated to theapproval byindividual operating segments. Thus, operating profit for each operating segment includes only theUnited States Bankruptcy Court following the conclusion of an auction process,costs that are directly attributable tobe conducted pursuant to the jurisdiction of the Bankruptcy Court, and is subject to regulatory approvals. The transaction will be accounted for using the purchase method of accounting. Under the terms of the Purchase Agreement, the Partnership would purchase all ofthe operations ofAgway Energy, including 139the 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
sales centersagricultural 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 firefurnaces 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
Pennsylvania, New JerseyandVermont. Agway Energy, basedPennsylvania. 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
Syracuse, New York, marketsthe sale, installation anddistributes propane, fuel oil, gasoline and diesel fuels and installs and servicesservicing of a wide variety of home comfort equipment and parts, particularly in theareaareas of heating, ventilation and air conditioning.ForThe All other business segment is comprised of the activities from our HomeTown Hearth & Grill and Suburban Franchising subsidiaries.
The following table presents certain data by reportable segment and provides a reconciliation of total operating segment information to the corresponding consolidated amounts for the periods presented:
Year Ended September 24,
2005September 25,
2004September 27,
2003Revenues: Propane $ 969,943 $ 856,109 $ 680,840 Fuel oil and refined fuels 431,223 281,682 — Natural gas and electricity 102,803 68,452 — HVAC 106,115 92,072 46,938 All other 10,150 8,939 7,297 Total revenues $ 1,620,234 $ 1,307,254 $ 735,075 Income (loss) before interest expense, loss on debt extinguishment and provision for income taxes: Propane $ 147,468 $ 143,933 $ 133,278 Fuel oil and refined fuels (6,474 ) 14,911 — Natural gas and electricity 6,463 4,154 — HVAC (12,423 ) (2,686 ) (4,281 ) All other (3,802 ) (8,125 ) (3,460 ) Corporate (62,865 ) (82,408 ) (45,687 ) Total income before interest expense, loss on debt extinguishment and provision for income taxes 68,367 69,779 79,850 Reconciliation to income from continuing operations Interest expense, net 40,374 40,832 33,629 Loss on debt extinguishment 36,242 — — Provision for income taxes 803 3 202 (Loss) income from continuing operations $ (9,052 ) $ 28,944 $ 46,019 Depreciation and amortization: Propane $ 25,393 $ 26,347 $ 22,908 Fuel oil and refined fuels 4,802 4,302 — Natural gas and electricity 967 555 — HVAC 1,509 640 80 All other 281 343 383 Corporate 4,810 4,556 4,149 Total depreciation and amortization $ 37,762 $ 36,743 $ 27,520
As of September 24,
2005September 25,
2004Assets Propane $ 735,094 $ 720,645 Fuel oil and refined fuels 124,232 121,386 Natural gas and electricity 30,294 26,630 HVAC 15,590 20,715 All other 4,990 4,941 Corporate 143,378 185,671 Eliminations (87,981 ) (87,981 ) Total assets $ 965,597 $ 992,007 Income (loss) before interest expense, loss on debt extinguishment and provision for income taxes for the HVAC segment for the year ended
June 30, 2003 Agway Energy provided service to more than 400,000 customers across all linesSeptember 24, 2005 included the non-cash charge ofbusiness$656 for goodwill impairment (see Note 6). In addition, depreciation andsold approximately 106.3 million gallons of propane and 356.8 million gallons of fuel oil, gasoline and diesel fuel to retail customers for residential, commercial, industrial and agricultural applications. While the Purchase Agreement has been reviewed and accepted by the Bankruptcy Court, there can be no assurance that the Partnership will ultimately be the successful bidder at the auction. F-24INDEX TO SUPPLEMENTAL FINANCIAL INFORMATION SUBURBAN ENERGY SERVICES GROUP LLC Page ---- Report of Independent Auditors............................................. F-25 Balance Sheets As of September 27, 2003 and September 28, 2002....................... F-26 Notes to Balance Sheets.................................................... F-27 F-25REPORT OF INDEPENDENT AUDITORS To the Stockholders of Suburban Energy Services Group LLC: In our opinion, the accompanying balance sheets present fairly, in all material respects, the financial position of Suburban Energy Services Group LLC at September 27, 2003 and September 28, 2002 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheets are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheets, assessing the accounting principles used and significant estimates made by management, and evaluating the overall balance sheet presentation. We believe that our audits provide a reasonable basis for our opinion. PricewaterhouseCoopers LLP Florham Park, NJ October 23, 2003 F-26SUBURBAN ENERGY SERVICES GROUP LLC BALANCE SHEETS
September September 27, 2003 28, 2002 ---------------- ----------------- ASSETS Current assets:Cash and cash equivalents $ 2,886 $ 4,363 ---------------- ----------------- Total current assets 2,886 4,363 Investment in Suburban Propane Partners, L.P. 1,566,483 1,924,003 Goodwill, net 3,112,560 3,112,560 ---------------- ----------------- Total assets $ 4,681,929 $ 5,040,926 ================ ================= LIABILITIES AND STOCKHOLDERS' EQUITY Total liabilities - - ---------------- ----------------- Stockholders' equity Common stock, $1 par value, 2,000 shares issued and outstanding 2,000 2,000 Additional paid in capital 1,853,333 3,405,108 Retained earnings 2,826,596 1,633,818 ---------------- ----------------- Total stockholders' equity 4,681,929 5,040,926 ---------------- ----------------- Total liabilities and stockholders' equity $ 4,681,929 $ 5,040,926 ================ =================The accompanying notes are an integral part of these balance sheets. F-27SUBURBAN ENERGY SERVICES GROUP LLC NOTES TO BALANCE SHEETS 1. ORGANIZATION AND FORMATION Suburban Energy Services Group LLC (the "Company") was formed on October 26, 1998 as a limited liability company pursuant to the Delaware Limited Liability Company Act. The Company was formed to purchase the general partner interests in Suburban Propane Partners, L.P. (the "Partnership") from Suburban Propane GP, Inc. (the "Former General Partner"), a wholly-owned indirect subsidiary of Millennium Chemicals Inc., and become the successor general partner. On May 26, 1999, the Company purchased a 1% general partner interest in the Partnership and a 1.0101% general partner interest in Suburban Propane, L.P., the Operating Partnership. The Partnership is a publicly-traded master limited partnership whose common units are listed on the New York Stock Exchange and is engaged in the retail and wholesale marketing of propane and related appliances and services. As a result of two public offerings by the Partnership on October 17, 2000 and June 18, 2003, the Company's interest in the Partnership was reduced to .701%. The Company's interest in Suburban Propane, L.P. was not affected. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES ACCOUNTING PERIOD. The Company's accounting period ends on the last Saturday nearest to September 30. USE OF ESTIMATES. The preparation of financial statements in conformity with generally accepted accounting principles 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. Actual results could differ from those estimates. CASH AND CASH EQUIVALENTS. The Company considers all highly liquid debt 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. INVESTMENT IN SUBURBAN PROPANE PARTNERS, L.P. As previously noted, the Company acquired a combined 2% general partner interest in the Partnership which was subsequently reduced to 1.71%. The Company accounts for its investment under the equity method of accounting whereby the Company recognizes in income its share of net income of Suburban Propane Partners, L.P. consolidated net income (loss) and reduces its investment balance to the extent of partnership distributions the Company receives from Suburban Propane Partners, L.P. GOODWILL. Goodwill represents the excess of the purchase priceamortization expense for thegeneral partner interests inHVAC segment for thePartnership overyear ended September 24, 2005 reflects thecarrying valuenon-cash charge of $810 for theGeneral Partner's capital account reflectedimpairment of otherintangible assets (see Note 6). Income (loss) before interest expense, loss on
the books of Suburban Propane Partners, L.P. on the date of acquisition. The Company tests goodwill for impairment on an annual basis using a two-step impairment test. The first step compares the fair value of the Company to the carrying value of the company. If the carrying value of the Company exceeds the fair value of the Company, a second step is performed comparing the implied fair value of the Company with the carrying amount of the Company's goodwill to determine the amount of goodwill impairment, if any. Based on the Company's annual goodwill impairment test, goodwill was not considered impaired as of September 27, 2003. F-28INCOME TAXES. For Federaldebt extinguishment andstate income tax purposes, the earnings and losses attributable to the Company are included in the tax returns of the individual stockholders. As a result, no recognition ofincome taxeshas been reflected infor theaccompanying balance sheets. RECENTLY ISSUED ACCOUNTING STANDARDS. In January 2003,All other segment for theFinancial Accounting Standards Board ("FASB") issued FASB Interpretation No. 46, "Consolidation of Variable Interest Entities" ("FIN 46"), an interpretation of Accounting Research Bulletin No. 51, "Consolidated Financial Statements." FIN 46 addresses consolidation by business enterprises of variable interest entities that meet certain characteristics. The consolidation requirements of FIN 46 apply immediately to variable interest entities created after January 31, 2003. The consolidation requirements apply to variable interest entities created before February 1, 2003 inyear ended September 25, 2004 included thefirst fiscal year or interim period beginning after June 15, 2003. However, in October 2003, the FASB deferred the effective date$3,177 non-cash charge forapplying certain provisions of FIN 46 and in November 2003, issued an exposure draft which would amend certain provisions of FIN 46. As a result of the latest exposure draft, the Company is currently evaluating the impact, if any, that FIN 46 or any future amendment may have on its financial position. F-29goodwill impairment.INDEX TO FINANCIAL STATEMENT SCHEDULE
SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES
Page ----
Page Schedule II Valuation and Qualifying Accounts – Years Ended September 24, 2005, September 25, 2004 and September 27, 2003 S-2 SCHEDULE II
Valuation and Qualifying Accounts - Years Ended September 27, 2003, September 28, 2002 and September 29, 2001........................................... S-2 S-1SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
(in
(in thousands)
Balance at
Beginning of
PeriodCharged to
Costs
and ExpensesOther
AdditionsDeductions Balance
at End
of PeriodYear Ended September 27, 2003 Allowance for doubtful accounts $ 1,894 $ 3,315 $ — $ (2,690 ) $ 2,519 Year Ended September 25, 2004 (a) Allowance for doubtful accounts $ 2,519 $ 9,128 $ 2,966 $ (6,717 ) $ 7,896 Year Ended September 24, 2005 Allowance for doubtful accounts $ 7,896 $ 9,289 $ — $ (7,220 ) $ 9,965
Balance at Charged Balance Beginning to Costs and(a) Other at End of Period Expenses Additions Deductions of Period ------------- ------------- ------------- ------------- ------------- YEAR ENDED SEPTEMBER 29, 2001Allowanceadditions for the year ended September 25, 2004 reflects allowances for doubtful accounts$ 2,975 $ 5,328 $ - $ (4,311) $ 3,992 ============= ============= ============= ============= ============= YEAR ENDED SEPTEMBER 28, 2002 Allowance for doubtfulassociated with the acquisition of Agway Energy. Additionally, the increase in charges and deductions during fiscal 2004 was primarily attributable to the impact of increased sales and related accounts$ 3,992 $ 1,147 $ - $ (3,245) $ 1,894 ============= ============= ============= ============= ============= YEAR ENDED SEPTEMBER 27, 2003 Allowance for doubtful accounts $ 1,894 $ 3,315 $ - $ (2,690) $ 2,519 ============= ============= ============= ============= =============receivable from the Agway Energy operations.S-2