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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549FORM 10-K
[X] Annual Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934For the fiscal year ended September 29, 2007
[ ] Transition Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934Commission File Number: 1-14222
SUBURBAN PROPANE PARTNERS, L.P.
(Exact name of registrant as specified in its charter)
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Delaware
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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, including zip code, and telephone number,
including area code, of registrant’s principal executive offices)Securities registered pursuant to Section 12(b) of the Act:
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Title of each class
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Name of each exchange on which registered Common Units
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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’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of ‘‘accelerated filer and large accelerated filer’’ in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer [X] Accelerated filer [ ] Non-accelerated filer [ ]
Indicate by check mark whether registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes [ ] No [X]
The aggregate market value as of March 30, 2007 of the registrant’s Common Units held by non-affiliates of the registrant, based on the reported closing price of such units on the New York Stock Exchange on such date ($44.00 per unit), was approximately $1,437,667,000.
Documents Incorporated by Reference: None Total number of pages (excluding Exhibits): 136
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SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES
INDEX TO ANNUAL REPORT ON FORM 10-K
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Page
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PART I
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ITEM 1.
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BUSINESS
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1
ITEM 1A.
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RISK FACTORS
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11
ITEM 1B.
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UNRESOLVED STAFF COMMENTS
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18
ITEM 2.
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PROPERTIES
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18
ITEM 3.
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LEGAL PROCEEDINGS
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18
ITEM 4.
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SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
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19
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PART II
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ITEM 5.
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MARKET FOR THE REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF UNITS
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20
ITEM 6.
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SELECTED FINANCIAL DATA
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ITEM 7.
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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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ITEM 7A.
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QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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45
ITEM 8.
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FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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48
ITEM 9.
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CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
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ITEM 9A.
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CONTROLS AND PROCEDURES
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ITEM 9B.
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OTHER INFORMATION
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PART III
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ITEM 10.
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DIRECTORS, EXECUTIVE OFFICERS AND PARTNERSHIP GOVERNANCE
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ITEM 11.
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EXECUTIVE COMPENSATION
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59
ITEM 12.
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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS
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90
ITEM 13.
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CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
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ITEM 14.
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PRINCIPAL ACCOUNTING FEES AND SERVICES
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PART IV
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ITEM 15.
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EXHIBITS, FINANCIAL STATEMENT SCHEDULES
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Signatures
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Table of ContentsDISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K contains forward-looking statements (‘‘Forward-Looking Statements’’) as defined in the Private Securities Litigation Reform Act of 1995 and Section 27A of the Securities Act of 1933, as amended, relating to future business expectations and predictions and financial condition and results of operations of Suburban Propane Partners, L.P. (the ‘‘Partnership’’). Some of these statements can be identified by the use of forward-looking terminology such as ‘‘prospects,’’ ‘‘outlook,’’ ‘‘believes,’’ ‘‘estimates,’’ ‘‘intends,’’ ‘‘may,’’ ‘‘will,’’ ‘‘should,’’ ‘‘anticipates,’’ ‘‘expects’’ or ‘‘plans’’ or the negative or other variation of these or similar words, or by discussion of trends and conditions, strategies or risks and uncertainties. These Forward-Looking Statements involve certain risks and uncertainties that could cause actual results to differ materially from those discussed or implied in such Forward-Looking Statements (statements contained in this Annual Report identifying such risks and uncertainties are referred to as ‘‘Cautionary Statements’’). The risks and uncertainties and their impact on the Partnership’s results include, but are not limited to, the following risks:
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• The impact of weather conditions on the demand for propane, fuel oil and other refined fuels, natural gas and electricity;
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• 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;
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• The ability of the Partnership to compete with other suppliers of propane, fuel oil and other energy sources;
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• 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;
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• The ability of the Partnership to acquire and maintain reliable transportation for its propane, fuel oil and other refined fuels;
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• The ability of the Partnership to retain customers;
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• The impact of energy efficiency and technology advances on the demand for propane and fuel oil;
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• The ability of management to continue to control expenses;
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• 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;
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• The impact of legal proceedings on the Partnership’s business;
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• The impact of operating hazards that could adversely affect the Partnership’s operating results to the extent not covered by insurance; and
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• The Partnership’s ability to make strategic acquisitions and successfully integrate them.
Some of these Forward-Looking Statements are discussed in more detail in ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’ in this Annual Report. On different occasions, the Partnership or its representatives have made or may make Forward-Looking Statements in other filings with the Securities and Exchange Commission (‘‘SEC’’), press releases or oral statements made by or with the approval of one of the Partnership’s authorized executive officers. Readers are cautioned not to place undue reliance on Forward-Looking Statements, which reflect management’s view only as of the date made. The Partnership undertakes no obligation to update any Forward-Looking Statement or Cautionary Statement, except as required by law. All subsequent written and oral Forward-Looking Statements attributable to the Partnership or persons acting on its behalf are expressly qualified in their entirety by the Cautionary Statements in this Annual Report and in future SEC reports. For a more complete discussion of specific factors which could cause actual results to differ from those in the Forward-Looking Statements or Cautionary Statements, see ‘‘Risk Factors’’ in this Annual Report.
Table of ContentsPART I
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ITEM 1. BUSINESS
Development of Business
Suburban Propane Partners, L.P. (the ‘‘Partnership’’), a publicly traded Delaware limited partnership, is a nationwide marketer and distributor of a diverse array of products meeting the energy needs of our customers. We specialize in the distribution of propane, fuel oil and refined fuels, as well as the marketing of natural gas and electricity in deregulated markets. In support of our core marketing and distribution operations, we install and service a variety of home comfort equipment, particularly in the areas of heating, ventilation and air conditioning (‘‘HVAC’’). We believe, based on LP/Gas Magazine dated February 2007, that we are the fourth largest retail marketer of propane in the United States, measured by retail gallons sold in the year 2006. As of September 29, 2007, we were serving the energy needs of approximately 1,000,000 active residential, commercial, industrial and agricultural customers through approximately 300 locations in 30 states located primarily in the east and west coast regions of the United States, including Alaska. We sold approximately 432.5 million gallons of propane to retail customers and 104.5 million gallons of fuel oil and refined fuels during the year ended September 29, 2007. Together with our predecessor companies, we have been continuously engaged in the retail propane business since 1928.
We conduct our business principally through Suburban Propane, L.P., a Delaware limited partnership, which operates our propane business and assets (the ‘‘Operating Partnership’’), and its direct and indirect subsidiaries. Our general partner, and the general partner of our Operating Partnership, is Suburban Energy Services Group LLC (the ‘‘General Partner’’), a Delaware limited liability company. Since October 19, 2006, the General Partner has had no economic interest in either the Partnership or the Operating Partnership other than as a holder of 784 Common Units of the Partnership. Prior to October 19, 2006, the General Partner was majority-owned by senior management of the Partnership and owned an approximate combined 1.75% general partner interest in the Partnership and the Operating Partnership.
On October 19, 2006, the Partnership, the Operating Partnership and the General Partner consummated an Exchange Agreement by and among the parties dated July 27, 2006 (the ‘‘Exchange Agreement’’), pursuant to which the Partnership issued 2,300,000 Common Units to the General Partner in exchange for the cancellation of the General Partner’s incentive distribution rights (‘‘IDRs’’), the economic interest in the Partnership included in the general partner interest therein and the economic interest in the Operating Partnership included in the general partner interest therein (the ‘‘GP Exchange Transaction’’). Pursuant to a Distribution, Release and Lockup Agreement dated July 27, 2006 by and among the Partnership, the Operating Partnership, the General Partner and the then individual members of the General Partner (the ‘‘Distribution Agreement’’), the Common Units received by the General Partner (other than 784 Common Units that will remain in the General Partner) were distributed to the then members of the General Partner in exchange for their interests in the General Partner.
In addition to the GP Exchange Transaction, the Partnership adopted the Third Amended and Restated Agreement of Limited Partnership (the ‘‘Partnership Agreement’’), which amended the Previous Partnership Agreement to, among other things, effectuate the GP Exchange Transaction. Under the Partnership Agreement, the General Partner will continue to be the general partner of both the Partnership and the Operating Partnership, but its general partner interests will have no economic value (which means that such general partner interests do not entitle the holder thereof to any cash distributions of either partnership, or to any cash payment upon the liquidation of either partnership, or any other economic rights in either partnership). Following the GP Exchange Transaction and the consummation of the Distribution Agreement, the sole member of the General Partner is the Chief Executive Officer of the Partnership and the General Partner holds 784 Common Units received in the GP Exchange Transaction. The Partnership continues to own all of the limited partner interests in the Operating Partnership, with 0.1% thereof held through a newly-organized
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Table of Contentslimited liability company, wholly-owned (directly and indirectly) by the Partnership. Additionally, under the Partnership Agreement no incentive distribution rights are outstanding and no provisions for future incentive distribution rights are contained in the Partnership Agreement. The Common Units now represent 100% of the limited partner interests in the Partnership.
Subsidiaries of the Operating Partnership include Suburban Sales and Service, Inc. (the ‘‘Service Company’’), which conducts a portion of the Partnership’s service work and appliance and parts businesses. The Service Company is the sole member of Gas Connection, LLC (d/b/a HomeTown Hearth & Grill), and Suburban Franchising, LLC. HomeTown Hearth & Grill sells and installs natural gas and propane gas grills, fireplaces and related accessories and supplies through six retail stores in the northwest and northeast regions as of September 29, 2007. Suburban Franchising creates and develops propane related franchising business opportunities.
On December 23, 2003, we acquired substantially all of the assets and operations of Agway Energy Products, LLC, Agway Energy Services, Inc. and Agway Energy Services PA, Inc. (collectively referred to as ‘‘Agway Energy’’) pursuant to an asset purchase agreement dated November 10, 2003 (the ‘‘Agway Acquisition’’). With the Agway Acquisition, we transformed our business from a marketer of a single fuel into one that provides multiple energy solutions, with expansion into the marketing and distribution of fuel oil and refined fuels, as well as the marketing of natural gas and electricity.
On November 21, 2003, Suburban Heating Oil Partners, LLC, a subsidiary of HomeTown Hearth & Grill, was formed to acquire and operate the fuel oil and refined fuels and HVAC businesses and assets of Agway Energy. In addition, Agway Energy Services, LLC, also a subsidiary of HomeTown Hearth & Grill, was formed to acquire and operate the natural gas and electricity marketing business of Agway Energy.
Suburban Energy Finance Corporation, a direct wholly-owned subsidiary of the Partnership, was formed on November 26, 2003 to serve as co-issuer, jointly and severally with the Partnership, of the Partnership’s unsecured 6.875% senior notes due December 2013. Suburban Energy Finance Corporation has nominal assets and conducts no business operations.
In this Annual Report, unless otherwise indicated, the terms ‘‘Partnership,’’ ‘‘we,’’ ‘‘us,’’ and ‘‘our’’ are used to refer to Suburban Propane Partners, L.P. or to Suburban Propane Partners, L.P. and its consolidated subsidiaries, including the Operating Partnership. The Partnership, the Operating Partnership and the Service Company commenced operations in March 1996 in connection with the Partnership’s initial public offering of Common Units.
We currently file Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and current reports on Form 8-K with the Securities and Exchange Commission (‘‘SEC’’). You may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Any information filed by us is also available on the SEC’s EDGAR database at www.sec.gov.
Upon written request or through a link from our website at www.suburbanpropane.com, we will provide, without charge, copies of our Annual Report on Form 10-K for the year ended September 29, 2007, each of the Quarterly Reports on Form 10-Q, current reports filed or furnished on Form 8-K and all amendments to such reports as soon as is reasonably practicable after such reports are electronically filed with or furnished to the SEC. Requests should be directed to: Suburban Propane Partners, L.P., Investor Relations, P.O. Box 206, Whippany, New Jersey 07981-0206.
Our Strategy
Our business strategy is to deliver increasing value to our Unitholders through initiatives, both internal and external, that are geared toward achieving sustainable profitable growth and increased quarterly distributions. The following are key elements of our strategy:
Internal Focus on Driving Operating Efficiencies, Reducing Our Cost Structure and Enhancing Our Customer Mix. We focus internally on improving the efficiency of our existing operations, managing
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Table of Contentsour cost structure and improving our customer mix. Through investments in our technology infrastructure, we continue to seek to improve operating efficiencies, particularly in the areas of routing, forecasting customer usage, inventory control and customer tracking. In furtherance of this strategy and to leverage our investments in technology, over the past two fiscal years (beginning at the end of fiscal 2005), we implemented plans to streamline our operating footprint and management structure, drive operating efficiencies, and refocus our HVAC activities on service offerings to support our existing customer base within our core operating segments. While the majority of the specific initiatives under these plans were executed by the end of fiscal 2007, our focus on operating efficiencies and on our cost structure is an ongoing process intended to support our strategy of achieving sustainable profitable growth.
In addition, we continually evaluate our customer base and, in particular, focus on customers that provide a proper return. In that regard, our efforts to strategically exit certain lower margin business in both our propane and fuel oil and refined fuels segments has resulted in a reduction in volumes sold, yet has had a favorable impact on overall segment profitability. Specifically, in our propane segment, our residential customer base accounted for a higher percentage of our overall volumes sold in fiscal 2007 compared to prior years, primarily from the reduction of certain low margin commercial, industrial and agricultural customers. In our fuel oil and refined fuels segment, our decision in fiscal 2005 to begin to exit the majority of our lower margin diesel and gasoline businesses has resulted in a decrease in volumes sold in fiscal 2007 compared to prior years.
Growing Our Customer Base by Improving Customer Retention and Acquiring New Customers. We set clear objectives to focus our employees on seeking new customers and retaining existing customers by providing world-class customer service. We believe that customer satisfaction is a critical factor in the growth and success of our operations. ‘‘Our Business is Customer Satisfaction’’ is one of our core operating philosophies. We measure and reward our customer service centers based on a combination of profitability of the individual customer service center and net customer growth.
Selective Acquisitions of Complementary Businesses or Assets. Externally, we seek to extend our presence or diversify our product offerings through selective acquisitions. Our acquisition strategy is to focus on businesses with a relatively steady cash flow that will extend our presence in strategically attractive markets, complement our existing business segments or provide an opportunity to diversify our operations with other energy-related assets. While we are active in this area, we are also very patient and deliberate in evaluating acquisition candidates. There were no acquisitions completed during fiscal 2007, 2006 or 2005 as we focused internally on driving efficiencies, reducing costs and integrating the operations of Agway Energy which were acquired in fiscal 2004. However, during fiscal 2007 we completed a non-cash transaction in which we disposed of nine customer service centers considered to be in markets that were non-strategic to our operations in exchange for three customer service centers located in Alaska, thus expanding our presence in this strategically attractive market.
Selective Disposition of Non-Strategic Assets. We continuously evaluate our existing facilities to identify opportunities to optimize our return on assets by selectively divesting operations in slower growing markets, generating proceeds that can be reinvested in markets that present greater opportunities for growth. Our objective is to fully exploit the growth and profit potential of all of our assets. In that regard, on October 2, 2007 (subsequent to the end of fiscal 2007) we completed the sale of our Tirzah, South Carolina underground granite propane storage cavern, and associated 62-mile pipeline, for approximately $54.0 million in net proceeds which will be reinvested in the business.
Business Segments
We manage and evaluate our operations in six segments, four of which are reportable segments: Propane, Fuel Oil and Refined Fuels, Natural Gas and Electricity and HVAC. These business segments are described below. See Note 16 to the Consolidated Financial Statements included in this Annual Report for financial information about our business segments.
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Table of ContentsPropane
Propane is a by-product of natural gas processing and petroleum refining. It is a clean burning energy source recognized for its transportability and ease of use relative to alternative forms of stand-alone energy sources. Propane use falls into three broad categories:
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• residential and commercial applications;
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• industrial applications; and
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• agricultural uses.
In the residential and commercial markets, propane is used primarily for space heating, water heating, clothes drying and cooking. Industrial customers use propane generally as a motor fuel to power over-the-road vehicles, forklifts and stationary engines, to fire furnaces, as a cutting gas and in other process applications. In the agricultural market, propane is primarily used for tobacco curing, crop drying, poultry brooding and weed control.
Propane is extracted from natural gas or oil wellhead gas at processing plants or separated from crude oil during the refining process. It is normally transported and stored in a liquid state under moderate pressure or refrigeration for ease of handling in shipping and distribution. When the pressure is released or the temperature is increased, propane becomes a flammable gas that is colorless and odorless, although an odorant is added to allow its detection. Propane is clean burning and, when consumed, produces only negligible amounts of pollutants.
Product Distribution and Marketing
We distribute propane through a nationwide retail distribution network consisting of approximately 300 locations in 30 states as of September 29, 2007. Our operations are concentrated in the east and west coast regions of the United States, including Alaska. In fiscal 2007, we serviced approximately 791,000 active propane customers. Typically, our customer service centers are located in suburban and rural areas where natural gas is not readily available. Generally, these customer service centers consist of an office, appliance showroom, warehouse and service facilities, with one or more 18,000 to 30,000 gallon storage tanks on the premises. Most of our residential customers receive their propane supply through an automatic delivery system that eliminates the customer’s need to make an affirmative purchase decision. These deliveries are scheduled through computer technology, based upon each customer’s historical consumption patterns and prevailing weather conditions. Additionally, as is common practice in the industry, we offer our customers a budget payment plan whereby the customer’s estimated annual propane purchases and service contracts are paid for in a series of estimated equal monthly payments over a twelve-month period. From our customer service centers, we also sell, install and service equipment to customers who purchase propane from us including heating and cooking appliances, hearth products and supplies and, at some locations, propane fuel systems for motor vehicles.
We sell propane primarily to six customer markets: residential, commercial, industrial (including engine fuel), agricultural, other retail users and wholesale. Approximately 91% of the propane gallons sold by us in fiscal 2007 were to retail customers: 44% to residential customers, 31% to commercial customers, 10% to industrial customers, 6% to agricultural customers and 9% to other retail users. The balance of approximately 9% of the propane gallons sold by us in fiscal 2007 was for risk management activities and wholesale customers. Sales to residential customers in fiscal 2007 accounted for approximately 70% of our margins on retail propane sales, reflecting the higher-margin nature of the residential market. No single customer accounted for 10% or more of our propane revenues during fiscal 2007.
Retail deliveries of propane are usually made to customers by means of bobtail and rack trucks. Propane is pumped from bobtail trucks, which have capacities ranging from 2,125 gallons to 2,975 gallons of propane, into a stationary storage tank on the customers’ premises. The capacity of these storage tanks ranges from approximately 100 gallons to approximately 1,200 gallons, with a typical tank having a capacity of 300 to 400 gallons. As is common in the propane industry, we own a
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Table of Contentssignificant portion of the storage tanks located on our customers’ premises. We also deliver propane to retail customers in portable cylinders, which typically have a capacity of 5 to 35 gallons. When these cylinders are delivered to customers, empty cylinders are refilled in place or transported for replenishment at our distribution locations. We also deliver propane to certain other bulk end users in larger trucks known as transports, which have an average capacity of approximately 9,000 gallons. End users receiving transport deliveries include industrial customers, large-scale heating accounts, such as local gas utilities that use propane as a supplemental fuel to meet peak load delivery requirements, and large agricultural accounts that use propane for crop drying.
In our wholesale operations, we principally sell propane to large industrial end users and other propane distributors. The wholesale market includes customers who use propane to fire furnaces, as a cutting gas and in other process applications. Due to the low margin nature of the wholesale market as compared to the retail market, we have reduced our emphasis on wholesale marketing over the last several years.
Supply
Our propane supply is purchased from approximately 66 oil companies and natural gas processors at approximately 125 supply points located in the United States and Canada. We make purchases primarily under one-year agreements that are subject to annual renewal, and also purchase propane on the spot market. Supply contracts generally provide for pricing in accordance with posted prices at the time of delivery or the current prices established at major storage points, and some contracts include a pricing formula that typically is based on prevailing market prices. Some of these agreements provide maximum and minimum seasonal purchase guidelines. Propane is generally transported from refineries, pipeline terminals, storage facilities (including our storage facility in Elk Grove, California) and coastal terminals to our customer service centers by a combination of common carriers, owner-operators and railroad tank cars. See Item 2 of this Annual Report.
Historically, supplies of propane have been readily available from our supply sources. Although we make no assurance regarding the availability of supplies of propane in the future, we currently expect to be able to secure adequate supplies during fiscal 2008. During fiscal 2007, Targa Liquids Marketing and Trade (‘‘Targa’’) and Enterprise Products Operating L.P. (‘‘Enterprise’’) provided approximately 18% and 10%, respectively, of our total domestic propane purchases. Aside from these two suppliers, no single supplier provided more than 10% of our total domestic propane supply during fiscal 2007. The availability of our propane supply is dependent on several factors, including the severity of winter weather and the price and availability of competing fuels, such as natural gas and fuel oil. We believe that if supplies from Targa or Enterprise were interrupted, we would be able to secure adequate propane supplies from other sources without a material disruption of our operations. Nevertheless, the cost of acquiring such propane might be higher and, at least on a short-term basis, margins could be affected. Approximately 94% of our total propane purchases were from domestic suppliers in fiscal 2007.
We seek to reduce the effect of propane price volatility on our product costs and to help ensure the availability of propane during periods of short supply. We are currently a party to propane futures transactions on the New York Mercantile Exchange (‘‘NYMEX’’) and to forward and option contracts with various third parties to purchase and sell product at fixed prices in the future. These activities are monitored by our senior management through enforcement of our Hedging and Risk Management Policy. See Items 7 and 7A of this Annual Report.
We own and operate a large propane storage facility in California. We also operate smaller storage facilities in other locations and have rights to use storage facilities in additional locations (including our former facility in Tirzah, South Carolina). These storage facilities enable us to buy and store large quantities of propane particularly during periods of low demand, which generally occur during the summer months. This practice helps ensure a more secure supply of propane during periods of intense demand or price instability. As of September 29, 2007, the majority of our storage capacity in California was leased to third parties. On October 2, 2007, we completed the sale of our Tirzah, South Carolina underground granite propane storage cavern, and associated 62-mile pipeline.
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Table of ContentsCompetition
According to the Energy Information Administration, propane accounts for approximately 4% of household energy consumption in the United States. This level has not changed materially over the previous two decades. As an energy source, propane competes primarily with natural gas, electricity and fuel oil, principally on the basis of price, availability and portability.
Propane is more expensive than natural gas on an equivalent British Thermal Unit basis in locations serviced by natural gas, but it is an alternative to natural gas in rural and suburban areas where natural gas is unavailable or portability of product is required. Historically, the expansion of natural gas into traditional propane markets has been inhibited by the capital costs required to expand pipeline and retail distribution systems. Although the recent extension of natural gas pipelines to previously unserved geographic areas tends to displace propane distribution in those areas, we believe new opportunities for propane sales have been arising as new neighborhoods are developed in geographically remote areas.
We also have some relative advantages over suppliers of other energy sources. For example, propane is generally less expensive to use than electricity for space heating, water heating, clothes drying and cooking. Fuel oil has not been a significant competitor due to the current geographical diversity of our operations, and propane and fuel oil are not significant competitors because of the cost of converting from one to the other.
In addition to competing with suppliers of other energy sources, our propane operations compete with other retail propane distributors. The retail propane industry is highly fragmented and competition generally occurs on a local basis with other large full-service multi-state propane marketers, thousands of smaller local independent marketers and farm cooperatives. Based on industry statistics contained in 2005 Sales of Natural Gas Liquids and Liquefied Refinery Gases, as published by the American Petroleum Institute in March 2007, and LP/Gas Magazine dated February 2007, the ten largest retailers, including us, account for approximately 39% of the total retail sales of propane in the United States, and no single marketer has a greater than 10% share of the total retail propane market in the United States. Most of our customer service centers compete with five or more marketers or distributors. However, each of our customer service centers operates in its own competitive environment because retail marketers tend to locate in close proximity to customers in order to lower the cost of providing service. Our typical customer service center has an effective marketing radius of approximately 50 miles, although in certain rural areas the marketing radius may be extended by a satellite office.
Fuel Oil and Refined Fuels
Product Distribution and Marketing
We market and distribute fuel oil, kerosene, diesel fuel and gasoline to approximately 97,000 residential and commercial customers in the northeast region of the United States. Sales of fuel oil and refined fuels for fiscal 2007 amounted to 104.5 million gallons. Approximately 60% of the refined fuel gallons sold by us in fiscal 2007 were to residential customers, principally for home heating, 8% were to commercial customers, 3% were to agricultural and 1% to other users. Fuel oil has a more limited use, compared to propane, for space and water heating in residential and commercial buildings. We sell diesel fuel and gasoline to commercial and industrial customers for use primarily to propel motor vehicles. Due to the low margin nature of the diesel fuel and gasoline businesses, at the end of fiscal 2005 we made a decision to reduce our emphasis on these activities and, in certain instances, exited the business. Sales of diesel and gasoline accounted for the remaining 28% of total volumes sold in this segment during fiscal 2007.
Approximately 70% of our fuel oil customers receive their fuel oil under an automatic delivery system without the customer having to make an affirmative purchase decision. These deliveries are scheduled through computer technology, based upon each customer’s historical consumption patterns and prevailing weather conditions. Additionally, as is common practice in the industry, we offer our
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Table of Contentscustomers a budget payment plan whereby the customer’s estimated annual fuel oil purchases and service contracts are paid for in a series of estimated equal monthly payments over a twelve-month period. From our customer service centers, we also sell, install and service equipment to customers who purchase fuel oil from us including heating appliances.
Deliveries of fuel oil are usually made to customers by means of tankwagon trucks, which have capacities ranging from 2,500 gallons to 3,000 gallons. Fuel oil is pumped from the tankwagon truck into a stationary storage tank that is located on the customer’s premises, which is owned by the customer. The capacity of customer storage tanks ranges from approximately 275 gallons to approximately 1,000 gallons. No single customer accounted for 10% or more of our fuel oil revenues during fiscal 2007.
Supply
We obtain fuel oil and other refined fuels in either pipeline, truckload or tankwagon quantities, and have contracts with certain pipeline and terminal operators for the right to temporarily store fuel oil at more than 13 terminal facilities we do not own. We have arrangements with certain suppliers of fuel oil, which provide open access to fuel oil at specific terminals throughout the northeast. Additionally, a portion of our purchases of fuel oil are made at local wholesale terminal racks. In most cases, the supply contracts do not establish the price of fuel oil in advance; rather, prices are typically established based upon market prices at the time of delivery plus or minus a differential to market for transportation and volume discounts. We purchase fuel oil from nearly 23 suppliers at approximately 69 supply points. While fuel oil supply is more susceptible to longer periods of constraint than propane, we believe that our supply arrangements will provide us with sufficient supply sources. Although we make no assurance regarding the availability of supplies of fuel oil in the future, we currently expect to be able to secure adequate supplies during fiscal 2008.
Competition
The fuel oil industry is a mature industry with total demand expected to remain relatively flat to moderately declining. The fuel oil industry is highly fragmented, characterized by a large number of relatively small, independently owned and operated local distributors. We compete with other fuel oil distributors offering a broad range of services and prices, from full service distributors to those that solely offer the delivery service. We have developed a wide range of sales programs and service offerings for our fuel oil customer base in an attempt to be viewed as a full service energy provider and to build customer loyalty. For instance, like most companies in the fuel oil business, we provide home heating equipment repair service to our fuel oil customers through our HVAC segment on a 24-hour a day basis. The fuel oil business unit also competes for retail customers with suppliers of alternative energy sources, principally natural gas, propane and electricity.
Natural Gas and Electricity
We market natural gas and electricity through our wholly-owned subsidiary Agway Energy Services, LLC (‘‘AES’’) in the deregulated markets of New York and Pennsylvania primarily to residential and small commercial customers. Historically, local utility companies provided their customers with all three aspects of electric and natural gas service: generation, transmission and distribution. However, under deregulation, public utility commissions in several states are licensing energy service companies, such as AES, to act as alternative suppliers of the commodity to end consumers. In essence, we make arrangements for the supply of electricity or natural gas to specific delivery points. The local utility companies continue to distribute electricity and natural gas on their distribution systems. The business strategy of this business segment is to expand its market share by concentrating on growth in the customer base and expansion into other deregulated markets that are considered strategic markets.
We serve nearly 71,000 natural gas and electricity customers in New York and Pennsylvania. During fiscal 2007, we sold approximately 4.4 million dekatherms of natural gas and 510.3 million kilowatt hours of electricity through the natural gas and electricity segment. Approximately 90% of
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Table of Contentsour customers were residential households and the remainder were small commercial and industrial customers. New accounts are obtained through numerous marketing and advertising programs, including telemarketing and direct mail initiatives. Most local utility companies have established billing service arrangements whereby customers receive a single bill from the local utility company which includes distribution charges from the local utility company, as well as product charges for the amount of natural gas or electricity provided by AES and utilized by the customer. We have arrangements with several local utility companies that provide billing and collection services for a fee. Under these arrangements, we are paid by the local utility company for all or a portion of customer billings after a specified number of days following the customer billing with no further recourse to AES.
Supply of natural gas is arranged through annual supply agreements with major national wholesale suppliers. Pricing under the annual natural gas supply contracts is based on posted market prices at the time of delivery, and some contracts include a pricing formula that typically is based on prevailing market prices. The majority of our electricity requirements are purchased through the New York Independent System Operator (‘‘NYISO’’) under an annual supply agreement, as well as purchase arrangements through other national wholesale suppliers on the open market. Electricity pricing under the NYISO agreement is based on local market indices at the time of delivery. Competition is primarily with local utility companies, as well as other marketers of natural gas and electricity providing similar alternatives as AES.
HVAC
We sell, install and service all types of whole-house heating products, air cleaners, humidifiers, de-humidifiers, hearth products and space heaters to the customers of our propane, fuel oil, natural gas and electricity products. We also offer services such as duct cleaning, air balancing and energy audits to those customers. Our supply needs are filled through supply arrangements with several large regional equipment manufacturers and distribution companies. Competition in this business segment is primarily with small, local HVAC providers and contractors, as well as, to a lesser extent, other regional service providers. During the third quarter of fiscal 2006, we initiated plans to restructure our HVAC service offerings and eliminated certain stand-alone installation activities. See Note 6 to the consolidated financial statements in this Annual Report. The focus of our ongoing service offerings will be in support of the service needs of our existing customer base within our propane, refined fuels and natural gas and electricity business segments. Additionally, we have entered into arrangements with third-party service providers to complement and, in certain instances, supplement our existing service capabilities.
All Other
Activities from our HomeTown Hearth & Grill and Suburban Franchising subsidiaries comprise the all other business caption.
Seasonality
The retail propane and fuel oil distribution businesses, as well as the natural gas marketing business, are seasonal because of the primary use of these fuels for heating in residential and commercial buildings. Historically, approximately two-thirds of our retail propane volume is sold during the six-month peak heating season from October through March. The fuel oil business tends to experience greater seasonality given its more limited use for space heating and approximately three-fourths of our fuel oil volumes are sold between October and March. Consequently, sales and operating profits are concentrated in our first and second fiscal quarters. Cash flows from operations, therefore, are greatest during the second and third fiscal quarters when customers pay for product purchased during the winter heating season. We expect lower operating profits and either net losses or lower net income during the period from April through September (our third and fourth fiscal quarters).
Weather conditions have a significant impact on the demand for our products, in particular propane, fuel oil and natural gas, for both heating and agricultural purposes. Many of our customers
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Table of Contentsrely heavily on propane, fuel oil or natural gas as a heating source. Accordingly, the volume sold is directly affected by the severity of the winter weather in our service areas, which can vary substantially from year to year. In any given area, sustained warmer than normal temperatures will tend to result in reduced propane, fuel oil and natural gas consumption, while sustained colder than normal temperatures will tend to result in greater use.
Trademarks and Tradenames
We utilize a variety of trademarks and tradenames owned by us, including ‘‘Suburban Propane,’’ ‘‘Gas Connection’’ and ‘‘HomeTown Hearth & Grill.’’ Additionally, in connection with the Agway Acquisition, we acquired rights to certain trademarks and tradenames, including ‘‘Agway Propane,’’ ‘‘Agway’’ and ‘‘Agway Energy Products’’ in connection with the distribution of petroleum-based fuel and sales and service of HVAC equipment. We regard our trademarks, tradenames and other proprietary rights as valuable assets and believe that they have significant value in the marketing of our products and services.
Government Regulation; Environmental and Safety Matters
We are subject to various federal, state and local environmental, health and safety laws and regulations. Generally, these laws impose limitations on the discharge of pollutants and establish standards for the handling of solid and hazardous wastes and can require the investigation and cleanup of environmental contamination. These laws include the Resource Conservation and Recovery Act, the Comprehensive Environmental Response, Compensation and Liability Act (‘‘CERCLA’’), the Clean Air Act, the Occupational Safety and Health Act, the Emergency Planning and Community Right to Know Act, the Clean Water Act and comparable state statutes. CERCLA, also known as the ‘‘Superfund’’ law, imposes joint and several liability without regard to fault or the legality of the original conduct on certain classes of persons that are considered to have contributed to the release or threatened release of a ‘‘hazardous substance’’ into the environment. Propane is not a hazardous substance within the meaning of CERCLA, whereas fuel oil is considered a hazardous substance. We own real property at locations where such hazardous substances may be present as a result of prior activities.
We expect that we will be required to expend funds to participate in the remediation of certain sites, including sites where we have been designated by the Environmental Protection Agency as a potentially responsible party under CERCLA and at sites with aboveground and underground fuel storage tanks. We will also incur other expenses associated with environmental compliance. We continually monitor our operations with respect to potential environmental issues, including changes in legal requirements and remediation technologies.
With the Agway Acquisition, we acquired certain surplus properties with either known or probable environmental exposure, some of which are currently in varying stages of investigation, remediation or monitoring. Additionally, we identified that certain active sites acquired contained environmental conditions which required further investigation, future remediation or ongoing monitoring activities. The environmental exposures included instances of soil and/or groundwater contamination associated with the handling and storage of fuel oil, gasoline and diesel fuel.
As of September 29, 2007, we had accrued environmental liabilities of $2.6 million representing the total estimated future liability for remediation and monitoring. For the portion of the estimated environmental liability that is recoverable under state environmental reimbursement funds, we record an asset within other assets related to the amount of the liability expected to be reimbursed by state agencies, which amounted to $0.1 million as of September 29, 2007.
Estimating the extent of our responsibility at a particular site, and the method and ultimate cost of remediation of that site, requires making numerous assumptions. As a result, the ultimate cost to remediate any site may differ from current estimates, and will depend, in part, on whether there is additional contamination, not currently known to us, at that site. However, we believe that our past experience provides a reasonable basis for estimating these liabilities. As additional information
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Table of Contentsbecomes available, estimates are adjusted as necessary. While we do not anticipate that any such adjustment would be material to our financial statements, the result of ongoing or future environmental studies or other factors could alter this expectation and require recording additional liabilities. We currently cannot determine whether we will incur additional liabilities or the extent or amount of any such liabilities.
National Fire Protection Association (‘‘NFPA’’) Pamphlet Nos. 54 and 58, which establish rules and procedures governing the safe handling of propane, or comparable regulations, have been adopted, in whole, in part or with state addenda, as the industry standard for propane storage, distribution and equipment installation and operation in all of the states in which we operate. In some states these laws are administered by state agencies, and in others they are administered on a municipal level. Pamphlet No. 58 has adopted storage tank valve retrofit requirements due to be completed by June 2011 or later depending on when each state adopts the 2001 edition of NFPA Pamphlet No. 58. We have a program in place to meet this deadline.
NFPA Pamphlet Nos. 30, 30A, 31, 385 and 395, which establish rules and procedures governing the safe handling of distillates (fuel oil, kerosene and diesel fuel) and gasoline, or comparable regulations, have been adopted, in whole, in part or with state addenda, as the industry standard for fuel oil, kerosene, diesel fuel and gasoline storage, distribution and equipment installation/operation in all of the states in which we operate. In some states these laws are administered by state agencies and in others they are administered on a municipal level.
With respect to the transportation of propane, distillates and gasoline by truck, we are subject to regulations promulgated under the Federal Motor Carrier Safety Act. These regulations cover the transportation of hazardous materials and are administered by the United States Department of Transportation or similar state agencies. We conduct ongoing training programs to help ensure that our operations are in compliance with applicable safety regulations. We maintain various permits that are necessary to operate some of our facilities, some of which may be material to our operations. We believe that the procedures currently in effect at all of our facilities for the handling, storage and distribution of propane, distillates and gasoline are consistent with industry standards and are in compliance, in all material respects, with applicable laws and regulations.
The Department of Homeland Security (‘‘DHS’’) has published new regulations under 6 CFR Part 27 Chemical Facility Anti-Terrorism Standards. Our facilities are registered with the DHS and are proceeding through the screening process. Because our facilities are currently operating under the security programs developed under guidelines issued by the Department of Transportation, Department of Labor and Environmental Protection Agency, we do not anticipate that we will incur additional material liabilities to comply with the DHS regulations.
Future developments, such as stricter environmental, health or safety laws and regulations thereunder, could affect our operations. We do not anticipate that the cost of our compliance with environmental, health and safety laws and regulations, including CERCLA, as currently in effect and applicable to known sites will have a material adverse effect on our financial condition or results of operations. To the extent we discover any environmental liabilities presently unknown to us or environmental, health or safety laws or regulations are made more stringent, however, there can be no assurance that our financial condition or results of operations will not be materially and adversely affected.
Employees
As of September 29, 2007, we had 3,144 full time employees, of whom 416 were engaged in general and administrative activities (including fleet maintenance), 43 were engaged in transportation and product supply activities and 2,685 were customer service center employees. As of September 29, 2007, 91 of our employees were represented by 8 different local chapters of labor unions. We believe that our relations with both our union and non-union employees are satisfactory. From time to time, we hire temporary workers to meet peak seasonal demands.
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ITEM 1A. RISK FACTORS
You should carefully consider the specific risk factors set forth below as well as the other information contained or incorporated by reference in this Annual Report. Some factors in this section are Forward-Looking Statements. See ‘‘Disclosure Regarding Forward-Looking Statements’’ above.
Risks Inherent in the Ownership of Our Common Units
Cash distributions are not guaranteed and may fluctuate with our performance and other external factors.
Cash distributions on our Common Units are not guaranteed, and depend primarily on our cash flow and our cash on hand. Because they are not dependent on profitability, which is affected by non-cash items, our cash distributions might be made during periods when we record losses and might not be made during periods when we record profits.
The amount of cash we generate may fluctuate based on our performance and other factors, including:
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• the impact of the risks inherent in our business operations, as described below;
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• required principal and interest payments on our debt and restrictions contained in our debt instruments;
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• issuances of debt and equity securities;
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• our ability to control expenses;
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• fluctuations in working capital;
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• capital expenditures; and
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• financial, business and other factors, a number of which will be beyond our control.
Our Partnership Agreement gives our Board of Supervisors broad discretion in establishing cash reserves for, among other things, the proper conduct of our business. These cash reserves will affect the amount of cash available for distributions.
We have substantial indebtedness. Our debt agreements may limit our ability to make distributions to Unitholders, as well as our financial flexibility.
As of September 29, 2007, we had total outstanding borrowings of $550.0 million, including $425.0 million of senior notes issued by the Partnership and our wholly-owned subsidiary, Suburban Energy Finance Corporation, and $125.0 million of borrowings under the Operating Partnership’s revolving credit facility. The payment of principal and interest on our debt will reduce the cash available to make distributions on our Common Units. In addition, we will not be able to make any distributions to our Unitholders if there is, or after giving effect to such distribution, there would be, an event of default under the indenture governing the senior notes. The amount of distributions that the Partnership makes to its Unitholders is limited by the senior notes, and the amount of distributions that the Operating Partnership may make to the Partnership is limited by the revolving credit facility. The amount and terms of our debt may also adversely affect our ability to finance future operations and capital needs, limit our ability to pursue acquisitions and other business opportunities and make our results of operations more susceptible to adverse economic and industry conditions. In addition to our outstanding indebtedness, we may in the future incur additional debt to finance acquisitions or for general business purposes, which could result in an increase in our leverage. Our ability to make principal and interest payments depends on our future performance, which is subject to many factors, some of which are beyond our control.
Unitholders have limited voting rights.
A Board of Supervisors manages our operations. Our Unitholders have only limited voting rights on matters affecting our business, including the right to elect the members of our Board of Supervisors every three years.
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Table of ContentsIt may be difficult for a third party to acquire us, even if doing so would be beneficial to our Unitholders.
Some provisions of our Partnership Agreement may discourage, delay or prevent third parties from acquiring us, even if doing so would be beneficial to our Unitholders. For example, our Partnership Agreement contains a provision, based on Section 203 of the Delaware General Corporation Law, that generally prohibits the Partnership from engaging in a business combination with a 15% or greater Unitholder for a period of three years following the date that person or entity acquired at least 15% of our outstanding Common Units, unless certain exceptions apply. Additionally, our Partnership Agreement sets forth advance notice procedures for a Unitholder to nominate a Supervisor to stand for election, which procedures may discourage or deter a potential acquiror from conducting a solicitation of proxies to elect the acquiror’s own slate of Supervisors or otherwise attempting to obtain control of the Partnership. These nomination procedures may not be revised or repealed, and inconsistent provisions may not be adopted, without the approval of the holders of at least 66-2/3% of the outstanding Common Units. These provisions may have an anti-takeover effect with respect to transactions not approved in advance by our Board of Supervisors, including discouraging attempts that might result in a premium over the market price of the Common Units held by our Unitholders.
Unitholders may not have limited liability in some circumstances.
A number of states have not clearly established limitations on the liabilities of limited partners for the obligations of a limited partnership. Our Unitholders might be held liable for our obligations as if they were general partners if:
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• a court or government agency determined that we were conducting business in the state but had not complied with the state’s limited partnership statute; or
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• Unitholders’ rights to act together to remove or replace the General Partner or take other actions under our Partnership Agreement are deemed to constitute ‘‘participation in the control’’ of our business for purposes of the state’s limited partnership statute.
Unitholders may have liability to repay distributions.
Unitholders will not be liable for assessments in addition to their initial capital investment in the Common Units. Under specific circumstances, however, Unitholders may have to repay to us amounts wrongfully returned or distributed to them. Under Delaware law, we may not make a distribution to Unitholders if the distribution causes our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and nonrecourse liabilities are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that a limited partner who receives a distribution of this kind and knew at the time of the distribution that the distribution violated Delaware law will be liable to the limited partnership for the distribution amount for three years from the distribution date. Under Delaware law, an assignee who becomes a substituted limited partner of a limited partnership is liable for the obligations of the assignor to make contributions to the partnership. However, such an assignee is not obligated for liabilities unknown to him at the time he or she became a limited partner if the liabilities could not be determined from the partnership agreement.
If we issue additional limited partner interests or other equity securities as consideration for acquisitions or for other purposes, the relative voting strength of each Unitholder will be diminished over time due to the dilution of each Unitholder’s interests and additional taxable income may be allocated to each Unitholder.
Our Partnership Agreement generally allows us to issue additional limited partner interests and other equity securities without the approval of our Unitholders. Therefore, when we issue additional Common Units or securities ranking on a parity with the Common Units, each Unitholder’s proportionate partnership interest will decrease, and the amount of cash distributed on each Common Unit and the market price of Common Units could decrease. The issuance of additional Common Units will also diminish the relative voting strength of each previously outstanding Common Unit. In
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Table of Contentsaddition, the issuance of additional Common Units will, over time, result in the allocation of additional taxable income, representing built-in gains at the time of the new issuance, to those Common Unitholders that existed prior to the new issuance.
Risks Inherent in our Business Operations
Since weather conditions may adversely affect demand for propane, fuel oil and other refined fuels and natural gas, our results of operations and financial condition are vulnerable to warm winters.
Weather conditions have a significant impact on the demand for propane, fuel oil and other refined fuels and natural gas for both heating and agricultural purposes. Many of our customers rely heavily on propane, fuel oil or natural gas as a heating source. The volume of propane, fuel oil and natural gas sold is at its highest during the six-month peak heating season of October through March and is directly affected by the severity of the winter. Typically, we sell approximately two-thirds of our retail propane volume and approximately three-fourths of our retail fuel oil volume during the peak heating season.
Actual weather conditions can vary substantially from year to year, significantly affecting our financial performance. For example, average temperatures in our service territories were 6% warmer than normal for the year ended September 29, 2007 compared to 11% warmer than normal temperatures in fiscal 2006 and 6% warmer than normal temperatures in fiscal 2005, as reported by the National Oceanic and Atmospheric Administration (‘‘NOAA’’). Furthermore, variations in weather in one or more regions in which we operate can significantly affect the total volume of propane, fuel oil and other refined fuels and natural gas we sell and, consequently, our results of operations. Variations in the weather in the northeast, where we have a greater concentration of higher margin residential accounts and substantially all of our fuel oil and natural gas operations, generally have a greater impact on our operations than variations in the weather in other markets. We can give no assurance that the weather conditions in any quarter or year will not have a material adverse effect on our operations, or that our available cash will be sufficient to pay principal and interest on our indebtedness and distributions to Unitholders.
Sudden increases in the price of propane, fuel oil and other refined fuels and natural gas due to, among other things, our inability to obtain adequate supplies from our usual suppliers, may adversely affect our operating results.
Our profitability in the retail propane, fuel oil and refined fuels and natural gas businesses is largely dependent on the difference between our product cost and retail sales price. Propane, fuel oil and other refined fuels and natural gas are commodities, and the unit price we pay is subject to volatile changes in response to changes in supply or other market conditions over which we have no control, including the severity of winter weather and the price and availability of competing alternative energy sources. In general, product supply contracts permit suppliers to charge posted prices at the time of delivery or the current prices established at major supply points, including Mont Belvieu, Texas, and Conway, Kansas. In addition, our supply from our usual sources may be interrupted due to reasons that are beyond our control. As a result, the cost of acquiring propane, fuel oil and other refined fuels and natural gas from other suppliers might be materially higher at least on a short-term basis. Since we may not be able to pass on to our customers immediately, or in full, all increases in our wholesale cost of propane, fuel oil and other refined fuels and natural gas, these increases could reduce our profitability. We engage in transactions to hedge certain product costs from time to time in an attempt to reduce cost volatility and to help ensure availability of product during periods of short supply. We can give no assurance that future volatility in propane, fuel oil and natural gas supply costs will not have a material adverse effect on our profitability and cash flow, or that our available cash will be sufficient to pay principal and interest on our indebtedness and distributions to our Unitholders.
Because of the highly competitive nature of the retail propane and fuel oil businesses, we may not be able to retain existing customers or acquire new customers, which could have an adverse impact on our operating results and financial condition.
The retail propane and fuel oil industries are mature and highly competitive. We expect overall demand for propane to remain relatively constant over the next several years, while we expect the
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Table of Contentsoverall demand for fuel oil to be relatively flat to moderately declining during the same period. Year-to-year industry volumes of propane and fuel oil are expected to be primarily affected by weather patterns and from competition intensifying during warmer than normal winters, as well as from the impact of a sustained higher commodity price environment on customer conservation.
Propane and fuel oil compete in the alternative energy sources market with electricity, natural gas and other existing and future sources of energy, some of which are, or may in the future be, less costly for equivalent energy value. For example, natural gas is a significantly less expensive source of energy than propane and fuel oil. As a result, except for some industrial and commercial applications, propane and fuel oil are generally not economically competitive with natural gas in areas where natural gas pipelines already exist. The gradual expansion of the nation’s natural gas distribution systems has made natural gas available in many areas that previously depended upon propane or fuel oil. Propane and fuel oil compete to a lesser extent with each other due to the cost of converting from one to the other.
In addition to competing with other sources of energy, our propane and fuel oil businesses compete with other distributors principally on the basis of price, service, availability and portability. Competition in the retail propane business is highly fragmented and generally occurs on a local basis with other large full-service multi-state propane marketers, thousands of smaller local independent marketers and farm cooperatives. Our fuel oil business competes with fuel oil distributors offering a broad range of services and prices, from full service distributors to those offering delivery only. Generally, our existing fuel oil customers, unlike our existing propane customers, own their own tanks. As a result, the competition for these customers is more intense than in our propane business, where our existing customers seeking to switch distributors may face additional transition costs and delays.
As a result of the highly competitive nature of the retail propane and fuel oil businesses, our growth within these industries depends on our ability to acquire other retail distributors, open new customer service centers, add new customers and retain existing customers. We believe our ability to compete effectively depends on reliability of service, responsiveness to customers and our ability to control expenses in order to maintain competitive prices.
Energy efficiency, general economic conditions and technological advances have affected and may continue to affect demand for propane and fuel oil by our retail customers.
The national trend toward increased conservation and technological advances, including installation of improved insulation and the development of more efficient furnaces and other heating devices, has adversely affected the demand for propane and fuel oil by our retail customers which, in turn, has resulted in lower sales volumes to our customers. In addition, recent economic conditions may lead to additional conservation by retail customers to further reduce their heating costs, particularly during periods of sustained higher commodity prices as has been the case over the past three fiscal years. Future technological advances in heating, conservation and energy generation may adversely affect our financial condition and results of operations.
Our operating results and ability to generate sufficient cash flow to pay principal and interest on our indebtedness, and to pay distributions to Unitholders, may be affected by our ability to continue to control expenses.
The propane and fuel oil industries are mature and highly fragmented with competition from other multi-state marketers and thousands of smaller local independent marketers. Demand for propane and fuel oil is expected to be affected by many factors beyond our control, including, but not limited to, the severity of weather conditions during the peak heating season, customer conservation driven by high energy costs and other economic factors, as well as technological advances impacting energy efficiency. Accordingly, our propane and fuel oil sales volumes and related gross margins may be negatively affected by these factors beyond our control. Our operating profits and ability to generate sufficient cash flow may depend on our ability to continue to control expenses in line with sales volumes. We can give no assurance that we will be able to continue to control expenses to the extent necessary to reduce the effect on our profitability and cash flow from these factors.
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Table of ContentsThe risk of terrorism and political unrest and the current hostilities in the Middle East may adversely affect the economy and the price and availability of propane, fuel oil and other refined fuels and natural gas.
Terrorist attacks and political unrest and the current hostilities in the Middle East may adversely impact the price and availability of propane, fuel oil and other refined fuels and natural gas, as well as our results of operations, our ability to raise capital and our future growth. The impact that the foregoing may have on our industry in general, and on us in particular, is not known at this time. An act of terror could result in disruptions of crude oil or natural gas supplies and markets (the sources of propane and fuel oil), and our infrastructure facilities could be direct or indirect targets. Terrorist activity may also hinder our ability to transport propane, fuel oil and other refined fuels if our means of supply transportation, such as rail or pipeline, become damaged as a result of an attack. A lower level of economic activity could result in a decline in energy consumption, which could adversely affect our revenues or restrict our future growth. Instability in the financial markets as a result of terrorism could also affect our ability to raise capital. Terrorist activity and hostilities in the Middle East could likely lead to increased volatility in prices for propane, fuel oil and other refined fuels and natural gas. We have opted to purchase insurance coverage for terrorist acts within our property and casualty insurance programs, but we can give no assurance that our insurance coverage will be adequate to fully compensate us for any losses to our business or property resulting from terrorist acts.
Our financial condition and results of operations may be adversely affected by governmental regulation and associated environmental and health and safety costs.
Our business is subject to a wide range of federal, state and local laws and regulations related to environmental and health and safety matters including those concerning, among other things, the investigation and remediation of contaminated soil and groundwater and transportation of hazardous materials. These requirements are complex, changing and tend to become more stringent over time. In addition, we are required to maintain various permits that are necessary to operate our facilities, some of which are material to our operations. There can be no assurance that we have been, or will be, at all times in complete compliance with all legal, regulatory and permitting requirements or that we will not incur material costs or liabilities in the future relating to such requirements. Violations could result in penalties, or the curtailment or cessation of operations.
Moreover, currently unknown environmental issues, such as the discovery of additional contamination, may result in significant additional expenditures, and potentially significant expenditures also could be required to comply with future changes to environmental laws and regulations or the interpretation or enforcement thereof. Such expenditures, if required, could have a material adverse effect on our business, financial condition or results of operations.
We are subject to operating hazards and litigation risks that could adversely affect our operating results to the extent not covered by insurance.
Our operations are subject to all operating hazards and risks normally associated with handling, storing and delivering combustible liquids such as propane, fuel oil and other refined fuels. As a result, we have been, and are likely to continue to be, a defendant in various legal proceedings and litigation arising in the ordinary course of business. We are self-insured for general and product, workers’ compensation and automobile liabilities up to predetermined amounts above which third-party insurance applies. We cannot guarantee that our insurance will be adequate to protect us from all material expenses related to potential future claims for personal injury and property damage or that these levels of insurance will be available at economical prices, nor that all legal matters that arise will be covered by our insurance programs.
If we are unable to make acquisitions on economically acceptable terms or effectively integrate such acquisitions into our operations, our financial performance may be adversely affected.
The retail propane and fuel oil industries are mature. We foresee only limited growth in total retail demand for propane and flat to moderately declining retail demand for fuel oil. With respect to
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Table of Contentsour retail propane business, because of the long-standing customer relationships that are typical in our industry, the inconvenience of switching tanks and suppliers and propane’s higher cost relative to other energy sources, such as natural gas, it may be difficult for us to acquire new retail propane customers except through acquisitions. As a result, we expect the success of our financial performance to depend, in part, upon our ability to acquire other retail propane and fuel oil distributors or other energy-related businesses and to successfully integrate them into our existing operations and to make cost saving changes. The competition for acquisitions is intense and we can make no assurance that we will be able to acquire other propane and fuel oil distributors or other energy-related businesses on economically acceptable terms or, if we do, to integrate the acquired operations effectively.
Tax Risks to Unitholders
Our tax treatment depends on our status as a partnership for federal income tax purposes. The IRS could treat us as a corporation, which would substantially reduce the cash available for distribution to Unitholders.
The anticipated after-tax economic benefit of an investment in our Common Units depends largely on our being treated as a partnership for federal income tax purposes. We believe that, under current law, we will be classified as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us. The IRS may adopt positions that differ from the positions we take. In addition, current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level federal income taxation. If we were treated as a corporation for federal income tax purposes, we would be required to pay tax on our income at corporate tax rates (currently a maximum of 35% federal rate) and likely would be required to pay state income tax at varying rates. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our Unitholders would be substantially reduced. Therefore, our treatment as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our Unitholders, likely causing a substantial reduction in the value of our Common Units.
A successful IRS contest of the federal income tax positions we take may adversely affect the market for our Common Units, and the cost of any IRS contest will reduce our cash available for distribution to our Unitholders.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with the positions we take. Any contest with the IRS may materially and adversely impact the market for our Common Units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our Unitholders because the costs will reduce our cash available for distribution.
A Unitholder’s tax liability could exceed cash distributions on its Common Units.
Because our Unitholders are treated as partners to whom we allocate taxable income which could be different in amount than the cash we distribute, a Unitholder is required to pay federal income taxes and, in some cases, state and local income taxes on its allocable share of our income, even if it receives no cash distributions from us. We cannot guarantee that a Unitholder will receive cash distributions equal to its allocable share of our taxable income or even the tax liability to it resulting from that income.
Ownership of Common Units may have adverse tax consequences for tax-exempt organizations and foreign investors.
Investment in Common Units by certain tax-exempt entities and foreign persons raises issues specific to them. For example, virtually all of our taxable income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be
16
Table of Contentsunrelated business taxable income and thus will be taxable to the Unitholder. Distributions to foreign persons will be reduced by withholding taxes at the highest applicable effective tax rate, and foreign persons will be required to file United States federal tax returns and pay tax on their share of our taxable income.
There are limits on a Unitholder’s deductibility of losses.
In the case of taxpayers subject to the passive loss rules (generally, individuals and closely held corporations), any losses generated by us will only be available to offset our future income and cannot be used to offset income from other activities, including other passive activities or investments. Unused losses may be deducted when the Unitholder disposes of its entire investment in us in a fully taxable transaction with an unrelated party. A Unitholder’s share of our net passive income may be offset by unused losses from us carried over from prior years, but not by losses from other passive activities, including losses from other publicly-traded partnerships.
Tax shelter registration could increase the risk of a potential audit by the IRS.
We registered as a ‘‘tax shelter’’ under the law in effect at the time of our initial public offering and were assigned tax shelter registration number 96080000050. The issuance of a tax shelter registration number to us does not indicate that a Common Unit investment in us or the claimed tax benefits have been reviewed, examined or approved by the IRS.
The tax gain or loss on the disposition of Common Units could be different than expected.
A Unitholder who sells Common Units will recognize a gain or loss equal to the difference between the amount realized, including its share of our nonrecourse liabilities, and its adjusted tax basis in the Common Units. Prior distributions in excess of cumulative net taxable income allocated to a Common Unit which decreased a Unitholder’s tax basis in that Common Unit will, in effect, become taxable income if the Common Unit is sold at a price greater than the Unitholder’s tax basis in that Common Unit, even if the price is less than the original cost of the Common Unit. A portion of the amount realized, if the amount realized exceeds the Unitholder’s adjusted basis in that Common Unit, will likely be characterized as ordinary income. Furthermore, should the IRS successfully contest some conventions used by us, a Unitholder could recognize more gain on the sale of Common Units than would be the case under those conventions, without the benefit of decreased income in prior years.
Reporting of partnership tax information is complicated and subject to audits.
We furnish each Unitholder with a Schedule K-1 that sets forth its allocable share of income, gains, losses and deductions. In preparing these schedules, we use various accounting and reporting conventions and adopt various depreciation and amortization methods. We cannot guarantee that these conventions will yield a result that conforms to statutory or regulatory requirements or to administrative pronouncements of the IRS. Further, our income tax return may be audited, which could result in an audit of a Unitholder’s income tax return and increased liabilities for taxes because of adjustments resulting from the audit.
We treat each purchaser of our Common Units as having the same tax benefits without regard to the actual Common Units purchased. The IRS may challenge this treatment, which could adversely affect the value of the Common Units.
Because we cannot match transferors and transferees of Common Units and because of other reasons, uniformity of the economic and tax characteristics of the Common Units to a purchaser of Common Units of the same class must be maintained. To maintain uniformity and for other reasons, we have adopted certain depreciation and amortization conventions which may be inconsistent with Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to a Unitholder. It also could affect the timing of these tax benefits or the amount of gain from the sale of Common Units, and could have a negative impact on the value of our Common Units or result in audit adjustments to a Unitholder’s income tax return.
17
Table of ContentsThere are state, local and other tax considerations for our Unitholders.
In addition to United States federal income taxes, Unitholders will likely be subject to other taxes, such as state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, even if the Unitholder does not reside in any of those jurisdictions. A Unitholder will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of the various jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. It is the responsibility of each Unitholder to file all United States federal, state and local income tax returns that may be required of such Unitholder.
Unitholders may have negative tax consequences if we default on our debt or sell assets.
If we default on any of our debt obligations, our lenders will have the right to sue us for non-payment. This could cause an investment loss and negative tax consequences for Unitholders through the realization of taxable income by Unitholders without a corresponding cash distribution. Likewise, if we were to dispose of assets and realize a taxable gain while there is substantial debt outstanding and proceeds of the sale were applied to the debt, Unitholders could have increased taxable income without a corresponding cash distribution.
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in a deemed termination (and reconstitution) of the Partnership for federal income tax purposes which would cause Unitholders to be allocated an increased amount of taxable income.
We will be deemed to have terminated (and reconstituted) for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Were this to occur, it would, among other things, result in the closing of our taxable year for all Unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income. This would result in Unitholders being allocated an increased amount of taxable income.
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ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
![]()
ITEM 2. PROPERTIES
As of September 29, 2007, we owned approximately 75% of our customer service center and satellite locations and leased the balance of our retail locations from third parties. We own and operate a 22 million gallon refrigerated, aboveground propane storage facility in Elk Grove, California. Effective October 2, 2007, we sold our 60 million gallon underground propane storage cavern in Tirzah, South Carolina. Additionally, we own our principal executive offices located in Whippany, New Jersey.
The transportation of propane requires specialized equipment. The trucks and railroad tank cars utilized for this purpose carry specialized steel tanks that maintain the propane in a liquefied state. As of September 29, 2007, we had a fleet of 11 transport truck tractors, of which we owned two, and 21 railroad tank cars, of which we owned one. In addition, as of September 29, 2007 we had 991 bobtail and rack trucks, of which we owned approximately 36%, 187 fuel oil tankwagons, of which we owned approximately 68%, and 1,333 other delivery and service vehicles, of which we owned approximately 52%. We lease the vehicles we do not own. As of September 29, 2007, we also owned approximately 831,401 customer propane storage tanks with typical capacities of 100 to 500 gallons, 173,835 customer propane storage tanks with typical capacities of over 500 gallons and 242,678 portable propane cylinders with typical capacities of five to ten gallons.
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ITEM 3. LEGAL PROCEEDINGS
Litigation
Our operations are subject to all operating hazards and risks normally incidental to handling, storing and delivering combustible liquids such as propane. As a result, we have been, and will
18
Table of Contentscontinue to be, a defendant in various legal proceedings and litigation arising in the ordinary course of business. We are self-insured for general and product, workers’ compensation and automobile liabilities up to predetermined amounts above which third party insurance applies. We believe that the self-insured retentions and coverage we maintain are reasonable and prudent. Although any litigation is inherently uncertain, based on past experience, the information currently available to us, and the amount of our self-insurance reserves for known and unasserted self-insurance claims (which was approximately $50.3 million at September 29, 2007), we do not believe that these pending or threatened litigation matters, or known claims or known contingent claims, will have a material adverse effect on our results of operations, financial condition or cash flow. For the portion of our estimated self-insurance liability that exceeds our deductibles, we record a corresponding asset related to the amount of the liability to be covered by insurance (which was approximately $13.9 million at September 29, 2007).
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ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
19
Table of ContentsPART II
![]()
ITEM 5. MARKET FOR THE REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF UNITS
(a) Our Common Units, representing limited partner interests in the Partnership, are listed and traded on the New York Stock Exchange (‘‘NYSE’’) under the symbol SPH. As of November 20, 2007, there were 785 Common Unitholders of record. The following table presents, for the periods indicated, the high and low sales prices per Common Unit, as reported on the NYSE, and the amount of quarterly cash distributions declared and paid per Common Unit in respect of each quarter.
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
Common Unit Price Range
![]()
Cash Distribution
Declared per Common Unit![]()
High
![]()
Low Fiscal 2006
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
First Quarter
![]()
![]()
$ 29.68
![]()
![]()
![]()
$ 23.51
![]()
![]()
![]()
$ 0.6125
Second Quarter
![]()
![]()
![]()
30.23
![]()
![]()
![]()
![]()
24.90
![]()
![]()
![]()
![]()
0.6125
Third Quarter
![]()
![]()
![]()
31.09
![]()
![]()
![]()
![]()
27.70
![]()
![]()
![]()
![]()
0.6375
Fourth Quarter
![]()
![]()
![]()
35.95
![]()
![]()
![]()
![]()
30.80
![]()
![]()
![]()
![]()
0.6625
Fiscal 2007
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
First Quarter
![]()
![]()
$ 39.15
![]()
![]()
![]()
$ 33.12
![]()
![]()
![]()
$ 0.6875
Second Quarter
![]()
![]()
![]()
44.22
![]()
![]()
![]()
![]()
35.11
![]()
![]()
![]()
![]()
0.7000
Third Quarter
![]()
![]()
![]()
49.58
![]()
![]()
![]()
![]()
43.96
![]()
![]()
![]()
![]()
0.7125
Fourth Quarter
![]()
![]()
![]()
49.50
![]()
![]()
![]()
![]()
38.70
![]()
![]()
![]()
![]()
0.7500
![]()
We make quarterly distributions to our partners in an aggregate amount equal to our Available Cash (as defined in our Partnership Agreement as adopted effective October 19, 2006, as amended) with respect to such quarter. Available Cash generally means all cash on hand at the end of the fiscal quarter plus all additional cash on hand as a result of borrowings subsequent to the end of such quarter less cash reserves established by the Board of Supervisors in its reasonable discretion for future cash requirements.
We are a publicly traded limited partnership and, other than certain corporate subsidiaries, we are not subject to federal income tax. Instead, Unitholders are required to report their allocable share of our earnings or loss, regardless of whether we make distributions.
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(b) Not applicable.
![]()
![]()
(c) None.
20
Table of Contents![]()
ITEM 6. SELECTED FINANCIAL DATA
The following table presents our selected consolidated historical financial data as derived from our audited consolidated financial statements, certain of which are included elsewhere in this Annual Report. All amounts in the table below, except per unit data, are in thousands.
![]()
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![]()
![]()
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![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
Year Ended
![]()
September 29,
2007![]()
September 30,
2006 (a)![]()
September 24,
2005![]()
September 25,
2004 (b)![]()
September 27,
2003 Statement of Operations Data![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
Revenues
![]()
![]()
$ 1,439,563
![]()
![]()
![]()
$ 1,657,130
![]()
![]()
![]()
$ 1,615,555
![]()
![]()
![]()
$ 1,301,943
![]()
![]()
![]()
$ 729,680
Costs and expenses
![]()
![]()
![]()
1,273,482
![]()
![]()
![]()
![]()
1,521,316
![]()
![]()
![]()
![]()
1,546,531
![]()
![]()
![]()
![]()
1,229,578
![]()
![]()
![]()
![]()
653,457
Restructuring charges and severance costs (c)
![]()
![]()
![]()
1,485
![]()
![]()
![]()
![]()
6,076
![]()
![]()
![]()
![]()
2,775
![]()
![]()
![]()
![]()
2,942
![]()
![]()
![]()
![]()
—
Impairment of goodwill (d)
![]()
![]()
![]()
—
![]()
![]()
![]()
![]()
—
![]()
![]()
![]()
![]()
656
![]()
![]()
![]()
![]()
3,177
![]()
![]()
![]()
![]()
—
Income before interest expense, loss on debt extinguishment and provision for income taxes (e)
![]()
![]()
![]()
164,596
![]()
![]()
![]()
![]()
129,738
![]()
![]()
![]()
![]()
65,593
![]()
![]()
![]()
![]()
66,246
![]()
![]()
![]()
![]()
76,223
Loss on debt extinguishment (f)
![]()
![]()
![]()
—
![]()
![]()
![]()
![]()
—
![]()
![]()
![]()
![]()
36,242
![]()
![]()
![]()
![]()
—
![]()
![]()
![]()
![]()
—
Interest expense, net
![]()
![]()
![]()
35,596
![]()
![]()
![]()
![]()
40,680
![]()
![]()
![]()
![]()
40,374
![]()
![]()
![]()
![]()
40,832
![]()
![]()
![]()
![]()
33,629
Provision for income taxes
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
Current
![]()
![]()
![]()
1,853
![]()
![]()
![]()
![]()
764
![]()
![]()
![]()
![]()
803
![]()
![]()
![]()
![]()
3
![]()
![]()
![]()
![]()
202
Deferred
![]()
![]()
![]()
3,800
![]()
![]()
![]()
![]()
—
![]()
![]()
![]()
![]()
—
![]()
![]()
![]()
![]()
—
![]()
![]()
![]()
![]()
—
Income (loss) from continuing operations (e)
![]()
![]()
![]()
123,347
![]()
![]()
![]()
![]()
88,294
![]()
![]()
![]()
![]()
(11,826 )
![]()
![]()
![]()
25,411
![]()
![]()
![]()
![]()
42,392
Discontinued operations:
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
Gain on disposal of discontinued operations (g)
![]()
![]()
![]()
1,887
![]()
![]()
![]()
![]()
—
![]()
![]()
![]()
![]()
976
![]()
![]()
![]()
![]()
26,332
![]()
![]()
![]()
![]()
2,483
Income from discontinued operations (h)
![]()
![]()
![]()
2,053
![]()
![]()
![]()
![]()
2,446
![]()
![]()
![]()
![]()
2,774
![]()
![]()
![]()
![]()
2,561
![]()
![]()
![]()
![]()
3,794
Net income (loss)
![]()
![]()
![]()
127,287
![]()
![]()
![]()
![]()
90,740
![]()
![]()
![]()
![]()
(8,076 )
![]()
![]()
![]()
54,304
![]()
![]()
![]()
![]()
48,669
Income (loss) from continuing operations per Common Unit – basic
![]()
![]()
![]()
3.79
![]()
![]()
![]()
![]()
2.76
![]()
![]()
![]()
![]()
(0.38 )
![]()
![]()
![]()
0.84
![]()
![]()
![]()
![]()
1.63
Net income (loss) per Common Unit – basic (i)
![]()
![]()
![]()
3.91
![]()
![]()
![]()
![]()
2.84
![]()
![]()
![]()
![]()
(0.26 )
![]()
![]()
![]()
1.79
![]()
![]()
![]()
![]()
1.87
Net income (loss) per Common Unit – diluted (i)
![]()
![]()
![]()
3.89
![]()
![]()
![]()
![]()
2.83
![]()
![]()
![]()
![]()
(0.26 )
![]()
![]()
![]()
1.78
![]()
![]()
![]()
![]()
1.86
Cash distributions declared per unit
![]()
![]()
$ 2.85
![]()
![]()
![]()
$ 2.53
![]()
![]()
![]()
$ 2.45
![]()
![]()
![]()
$ 2.41
![]()
![]()
![]()
$ 2.33
Balance Sheet Data (end of period)
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
Cash and cash equivalents
![]()
![]()
$ 96,586
![]()
![]()
![]()
$ 60,571
![]()
![]()
![]()
$ 14,411
![]()
![]()
![]()
$ 53,481
![]()
![]()
![]()
$ 15,765
Current assets
![]()
![]()
![]()
282,211
![]()
![]()
![]()
![]()
235,351
![]()
![]()
![]()
![]()
236,803
![]()
![]()
![]()
![]()
252,894
![]()
![]()
![]()
![]()
98,912
Total assets
![]()
![]()
![]()
975,218
![]()
![]()
![]()
![]()
945,566
![]()
![]()
![]()
![]()
959,305
![]()
![]()
![]()
![]()
988,323
![]()
![]()
![]()
![]()
668,492
Current liabilities, excluding short-term borrowings and current portion of long-term borrowings
![]()
![]()
![]()
196,410
![]()
![]()
![]()
![]()
192,616
![]()
![]()
![]()
![]()
194,987
![]()
![]()
![]()
![]()
202,024
![]()
![]()
![]()
![]()
94,802
Total debt
![]()
![]()
![]()
548,538
![]()
![]()
![]()
![]()
548,304
![]()
![]()
![]()
![]()
575,295
![]()
![]()
![]()
![]()
515,915
![]()
![]()
![]()
![]()
383,826
Other long-term liabilities
![]()
![]()
![]()
63,993
![]()
![]()
![]()
![]()
103,945
![]()
![]()
![]()
![]()
112,907
![]()
![]()
![]()
![]()
102,266
![]()
![]()
![]()
![]()
105,786
Partners’ capital – Common Unitholders
![]()
![]()
![]()
208,230
![]()
![]()
![]()
![]()
170,151
![]()
![]()
![]()
![]()
159,199
![]()
![]()
![]()
![]()
238,880
![]()
![]()
![]()
![]()
165,950
Partner’s (deficit) capital – General Partner
![]()
![]()
$ —
![]()
![]()
![]()
$ (1,969 )
![]()
![]()
$ (1,779 )
![]()
![]()
$ 852
![]()
![]()
![]()
$ 1,567
Statement of Cash Flows Data
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
Cash provided by (used in)
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
Operating activities
![]()
![]()
$ 145,957
![]()
![]()
![]()
$ 170,321
![]()
![]()
![]()
$ 39,005
![]()
![]()
![]()
$ 93,065
![]()
![]()
![]()
$ 57,300
Investing activities
![]()
![]()
![]()
(19,689 )
![]()
![]()
![]()
(19,092 )
![]()
![]()
![]()
(24,631 )
![]()
![]()
![]()
(196,557 )
![]()
![]()
![]()
(4,859 ) Financing activities
![]()
![]()
$ (90,253 )
![]()
![]()
$ (105,069 )
![]()
![]()
$ (53,444 )
![]()
![]()
$ 141,208
![]()
![]()
![]()
$ (77,631 ) Other Data
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
Depreciation and amortization – continuing operations
![]()
![]()
$ 28,790
![]()
![]()
![]()
$ 32,653
![]()
![]()
![]()
$ 37,260
![]()
![]()
![]()
$ 36,236
![]()
![]()
![]()
$ 26,978
Depreciation and amortization – discontinued operations
![]()
![]()
![]()
452
![]()
![]()
![]()
![]()
498
![]()
![]()
![]()
![]()
502
![]()
![]()
![]()
![]()
507
![]()
![]()
![]()
![]()
542
![]()
21
Table of Contents
![]()
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![]()
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![]()
![]()
![]()
![]()
![]()
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![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
Year Ended
![]()
September 29,
2007![]()
September 30,
2006 (a)![]()
September 24,
2005![]()
September 25,
2004 (b)![]()
September 27,
2003 EBITDA and Adjusted EBITDA (j)![]()
![]()
![]()
197,778
![]()
![]()
![]()
![]()
165,335
![]()
![]()
![]()
![]()
107,105
![]()
![]()
![]()
![]()
131,882
![]()
![]()
![]()
![]()
110,020
Capital expenditures – maintenance and
growth (k)![]()
![]()
![]()
26,756
![]()
![]()
![]()
![]()
23,057
![]()
![]()
![]()
![]()
29,301
![]()
![]()
![]()
![]()
26,527
![]()
![]()
![]()
![]()
14,050
Acquisitions
![]()
![]()
$ —
![]()
![]()
![]()
$ —
![]()
![]()
![]()
$ —
![]()
![]()
![]()
$ 211,181
![]()
![]()
![]()
$ —
Retail gallons sold
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
Propane
![]()
![]()
![]()
432,526
![]()
![]()
![]()
![]()
466,779
![]()
![]()
![]()
![]()
516,040
![]()
![]()
![]()
![]()
537,330
![]()
![]()
![]()
![]()
491,451
Fuel oil and refined fuels
![]()
![]()
![]()
104,506
![]()
![]()
![]()
![]()
145,616
![]()
![]()
![]()
![]()
244,536
![]()
![]()
![]()
![]()
220,469
![]()
![]()
![]()
![]()
—
![]()
![]()
![]()
![]()
(a) Fiscal 2006 includes 53 weeks of operations compared to 52 weeks in each of fiscal 2007, 2005, 2004 and 2003. (b) Fiscal 2004 includes the results from our acquisition of substantially all of the assets and operations of Agway Energy from December 23, 2003, the date of acquisition. (c) During fiscal 2007, we incurred $1.5 million in charges associated with severance for positions eliminated unrelated to any specific plan of restructuring. During fiscal 2006, we incurred $6.1 million in restructuring charges associated primarily with severance costs from our field realignment efforts initiated during the fourth quarter of fiscal 2005, including the restructuring of our HVAC segment. During fiscal 2005, we incurred $2.8 million in restructuring charges associated primarily with severance costs from the realignment of our field operations. During fiscal 2004, we incurred $2.9 million in restructuring charges to integrate our assets, employees and operations with Agway Energy assets, employees and operations. (d) During 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. (e) These amounts include gains from the disposal of property, plant and equipment of $2.8 million for fiscal 2007, $1.0 million for fiscal 2006, $2.0 million for fiscal 2005, $0.7 million for fiscal 2004 and $0.6 million for fiscal 2003. (f) During fiscal 2005, we incurred a one-time charge of $36.2 million as a result of our March 31, 2005 debt refinancing to reflect the loss on debt extinguishment associated with a prepayment premium of $32.0 million and the write-off of $4.2 million of unamortized bond issuance costs associated with the previously outstanding senior notes. (g) Gain on disposal of discontinued operations for fiscal 2007 of $1.9 million reflects the exchange, in a non-cash transaction, of nine non-strategic customer service centers for three customer service centers of another company in Alaska, as well as the sale of three additional customer service centers for net cash proceeds of $1.3 million. Gain on disposal of discontinued operations for fiscal 2005 of $1.0 million reflects the finalization of certain purchase price adjustments with the buyer of the customer service centers sold during fiscal 2004. Gain on disposal of discontinued operations 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 disposal of discontinued operations 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 disposal 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’’ (‘‘SFAS 144’’). Prior period results of operations attributable to the customer service centers sold during fiscal 2007 were not significant and, as such, prior period results were not reclassified to remove financial results from continuing operations. The prior period results of operations attributable to the customer service centers sold in fiscal 2004 have been reclassified to remove financial results from continuing operations.
22
Table of Contents (h) On October 2, 2007, we completed the sale of our Tirzah, South Carolina underground granite propane storage cavern, and associated 62-mile pipeline, for approximately $54.0 million in net proceeds (the ‘‘Tirzah Sale’’). The 57.5 million gallon underground storage cavern is connected to the Dixie Pipeline and provides propane storage for the eastern United States. As a result of this sale, a gain of approximately $40.0 million will be reported as a gain from the disposal of discontinued operations in our results for the first quarter of fiscal 2008. The results of operations from the Tirzah facilities have been reported within discontinued operations. Because the transaction closed subsequent to the end of fiscal 2007, our cash on hand at September 29, 2007 does not include the net proceeds of approximately $54.0 million. (i) Computations of earnings per Common Unit for the year ended September 29, 2007 were performed in accordance with SFAS No. 128 ‘‘Earnings per Share’’ (‘‘SFAS 128’’) by dividing net income by the weighted average number of outstanding Common Units. For fiscal 2006, earnings per Common Unit were performed in accordance with Emerging Issues Task Force consensus 03-6 ‘‘Participating Securities and the Two-Class Method Under FAS 128’’ (‘‘EITF 03-6’’), when applicable. EITF 03-6 requires, among other things, the use of the two-class method of computing earnings per unit when participating securities exist. The two-class method is an earnings allocation formula that computes earnings per unit for each class of Common Unit and participating security according to distributions declared and participating rights in undistributed earnings, as if all of the earnings were distributed to the limited partners and the General Partner (inclusive of the previously outstanding IDRs of the General Partner which were considered participating securities for purposes of the two-class method). Net income was allocated to the Common Unitholders and the General Partner in accordance with their respective partnership ownership interests, after giving effect to any priority income allocations for IDRs of the General Partner. As a result of the GP Exchange Transaction on October 19, 2006, the two-class method of computing income per Common Unit under EITF 03-6 is no longer applicable.The requirements of EITF 03-6, which we adopted at the end of fiscal 2004, do not apply to the computation of earnings per Common Unit in periods in which a net loss is reported and therefore did not have any impact on loss per Common Unit for the year ended September 24, 2005, nor did it have any impact on income per Common Unit for the years ended September 25, 2004 or September 27, 2003. Application of the two-class method under EITF 03-6 had a negative impact on income per Common Unit of $0.07 for the year ended September 30, 2006 compared to the computation under SFAS No. 128. Basic net income (loss) per Common Unit for the years ended September 24, 2005, September 25, 2004 and September 27, 2003 was computed under SFAS 128 by dividing net income (loss), after deducting our General Partner’s interest, by the weighted average number of outstanding Common Units. Diluted net income (loss) per Common Unit for these same periods was computed by dividing net income (loss), after deducting our General Partner’s interest, by the weighted average number of outstanding Common Units and unvested restricted units under our 2000 Restricted Unit Plan. For purposes of the computation of income per Common Unit for the year ended September 30, 2007, earnings that would have been allocated to the General Partner for the period prior to the GP Exchange Transaction were not significant.
(j) EBITDA represents net income before deducting interest expense, income taxes, depreciation and amortization. Our management uses EBITDA as a measure of liquidity and we are including it because we believe that it provides our investors and industry analysts with additional information to evaluate our ability to meet our debt service obligations and to pay our quarterly distributions to holders of our Common Units. In addition, certain of our incentive compensation plans covering executives and other employees utilize EBITDA as the performance target. We use the term Adjusted EBITDA to reflect the presentation of EBITDA for the year ended September 24, 2005 exclusive of the impact of the non-cash charge for loss on debt extinguishment in the amount of $36.2 million. We use this non-GAAP financial measure in order to assist industry analysts and investors in assessing our liquidity on a year-over-year basis. Moreover, our revolving credit agreement requires us to use EBITDA or Adjusted EBITDA as a component in calculating our leverage and interest coverage ratios. EBITDA and Adjusted EBITDA are not23
Table of Contents recognized terms under generally accepted accounting principles (‘‘GAAP’’) and should not be considered as alternatives to net income or net cash provided by operating activities determined in accordance with GAAP. Because EBITDA as determined by us excludes some, but not all, items that affect net income, it may not be comparable to EBITDA or similarly titled measures used by other companies. The following table sets forth (i) our calculations of EBITDA and Adjusted EBITDA and (ii) a reconciliation of EBITDA and Adjusted EBITDA, as so calculated, to our net cash provided by operating activities (amounts in thousands):
(k) Our capital expenditures fall generally into two categories: (i) maintenance expenditures, which include expenditures for repair and replacement of property, plant and equipment; and (ii) growth capital expenditures which include new propane tanks and other equipment to facilitate expansion of our customer base and operating capacity.![]()
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![]()
![]()
![]()
![]()
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![]()
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![]()
![]()
Fiscal
2007![]()
Fiscal
2006![]()
Fiscal
2005![]()
Fiscal
2004![]()
Fiscal
2003 Net income (loss)![]()
![]()
$ 127,287
![]()
![]()
![]()
$ 90,740
![]()
![]()
![]()
$ (8,076 )
![]()
![]()
$ 54,304
![]()
![]()
![]()
$ 48,669
Add:
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
Provision for income taxes
![]()
![]()
![]()
5,653
![]()
![]()
![]()
![]()
764
![]()
![]()
![]()
![]()
803
![]()
![]()
![]()
![]()
3
![]()
![]()
![]()
![]()
202
Interest expense, net
![]()
![]()
![]()
35,596
![]()
![]()
![]()
![]()
40,680
![]()
![]()
![]()
![]()
40,374
![]()
![]()
![]()
![]()
40,832
![]()
![]()
![]()
![]()
33,629
Depreciation and amortization
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
Continuing operations
![]()
![]()
![]()
28,790
![]()
![]()
![]()
![]()
32,653
![]()
![]()
![]()
![]()
37,260
![]()
![]()
![]()
![]()
36,236
![]()
![]()
![]()
![]()
26,978
Discontinued operations
![]()
![]()
![]()
452
![]()
![]()
![]()
![]()
498
![]()
![]()
![]()
![]()
502
![]()
![]()
![]()
![]()
507
![]()
![]()
![]()
![]()
542
EBITDA
![]()
![]()
![]()
197,778
![]()
![]()
![]()
![]()
165,335
![]()
![]()
![]()
![]()
70,863
![]()
![]()
![]()
![]()
131,882
![]()
![]()
![]()
![]()
110,020
Loss on debt extinguishment
![]()
![]()
![]()
—
![]()
![]()
![]()
![]()
—
![]()
![]()
![]()
![]()
36,242
![]()
![]()
![]()
![]()
—
![]()
![]()
![]()
![]()
—
Adjusted EBITDA
![]()
![]()
![]()
197,778
![]()
![]()
![]()
![]()
165,335
![]()
![]()
![]()
![]()
107,105
![]()
![]()
![]()
![]()
131,882
![]()
![]()
![]()
![]()
110,020
Add (subtract):
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
Provision for income taxes – current
![]()
![]()
![]()
(1,853 )
![]()
![]()
![]()
(764 )
![]()
![]()
![]()
(803 )
![]()
![]()
![]()
(3 )
![]()
![]()
![]()
(202 ) Loss on debt extinguishment
![]()
![]()
![]()
—
![]()
![]()
![]()
![]()
—
![]()
![]()
![]()
![]()
(36,242 )
![]()
![]()
![]()
—
![]()
![]()
![]()
![]()
—
Interest expense, net
![]()
![]()
![]()
(35,596 )
![]()
![]()
![]()
(40,680 )
![]()
![]()
![]()
(40,374 )
![]()
![]()
![]()
(40,832 )
![]()
![]()
![]()
(33,629 ) Compensation cost recognized under Restricted Unit Plan
![]()
![]()
![]()
3,014
![]()
![]()
![]()
![]()
2,221
![]()
![]()
![]()
![]()
1,805
![]()
![]()
![]()
![]()
1,171
![]()
![]()
![]()
![]()
862
Gain on disposal of property, plant and equipment, net
![]()
![]()
![]()
(2,782 )
![]()
![]()
![]()
(1,000 )
![]()
![]()
![]()
(2,043 )
![]()
![]()
![]()
(715 )
![]()
![]()
![]()
(636 ) Gain on disposal of discontinued operations
![]()
![]()
![]()
(1,887 )
![]()
![]()
![]()
—
![]()
![]()
![]()
![]()
(976 )
![]()
![]()
![]()
(26,332 )
![]()
![]()
![]()
(2,483 ) Pension settlement charge
![]()
![]()
![]()
3,269
![]()
![]()
![]()
![]()
4,437
![]()
![]()
![]()
![]()
—
![]()
![]()
![]()
![]()
5,337
![]()
![]()
![]()
![]()
—
Changes in working capital and other assets and liabilities
![]()
![]()
![]()
(15,986 )
![]()
![]()
![]()
40,772
![]()
![]()
![]()
![]()
10,533
![]()
![]()
![]()
![]()
22,557
![]()
![]()
![]()
![]()
(16,632 ) Net cash provided by operating activities
![]()
![]()
$ 145,957
![]()
![]()
![]()
$ 170,321
![]()
![]()
![]()
$ 39,005
![]()
![]()
![]()
$ 93,065
![]()
![]()
![]()
$ 57,300
![]()
24
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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.
The following are factors that regularly affect our operating results and financial condition. In addition, our business is subject to the risks and uncertainties described in Item 1A of this Annual Report.
Product Costs and Supply
The level of profitability in the retail propane, fuel oil, natural gas and electricity businesses is largely dependent on the difference between retail sales price and product cost. The unit cost of our products, particularly propane, fuel oil and natural gas, is subject to volatility as a result of product supply or other market conditions, including, but not limited to, economic and political factors impacting crude oil and natural gas supply or pricing. We enter into product supply contracts that are generally one-year agreements subject to annual renewal, and also purchase product on the open market. We attempt to reduce price risk by pricing product on a short-term basis. Our propane supply contracts typically provide for pricing based upon index formulas using the posted prices established at major supply points such as Mont Belvieu, Texas, or Conway, Kansas (plus transportation costs) at the time of delivery. In certain instances, and when market conditions are favorable as was the case in the fuel oil market during the first half of fiscal 2007, we are able to purchase product under our supply arrangements at a discount to the market.
In addition, to supplement our annual purchase requirements, we may utilize forward fixed price purchase contracts to acquire a portion of the propane that we resell to our customers, which allows us to manage our exposure to unfavorable changes in commodity prices and to assure adequate physical supply. The percentage of contract purchases, and the amount of supply contracted for under forward contracts at fixed prices, will vary from year to year based on market conditions.
Product cost changes can occur rapidly over a short period of time and can impact profitability. There is no assurance that we will be able to pass on product cost increases fully or immediately, particularly when product costs increase rapidly. Therefore, average retail sales prices can vary significantly from year to year as product costs fluctuate with propane, fuel oil, crude oil and natural gas commodity market conditions. In addition, in periods of sustained higher commodity prices, as has been experienced over the past several fiscal years, retail sales volumes may be negatively impacted by customer conservation efforts.
Seasonality
The retail propane and fuel oil distribution businesses, as well as the natural gas marketing business, are seasonal because of the primary use for heating in residential and commercial buildings. Historically, approximately two-thirds of our retail propane volume is sold during the six-month peak heating season from October through March. The fuel oil business tends to experience greater seasonality given its more limited use for space heating and approximately three-fourths of our fuel oil volumes are sold between October and March. Consequently, sales and operating profits are concentrated in our first and second fiscal quarters. Cash flows from operations, therefore, are greatest during the second and third fiscal quarters when customers pay for product purchased during the winter heating season. We expect lower operating profits and either net losses or lower net income during the period from April through September (our third and fourth fiscal quarters). To the extent necessary, we will reserve cash from the second and third quarters for distribution to holders of our Common Units in the first and fourth fiscal quarters.
Weather
Weather conditions have a significant impact on the demand for our products, in particular propane, fuel oil and natural gas, for both heating and agricultural purposes. Many of our customers
25
rely heavily on propane, fuel oil or natural gas as a heating source. Accordingly, the volume sold is directly affected by the severity of the winter weather in our service areas, which can vary substantially from year to year. In any given area, sustained warmer than normal temperatures will tend to result in reduced propane, fuel oil and natural gas consumption, while sustained colder than normal temperatures will tend to result in greater use.
Hedging and Risk Management Activities
We engage in hedging and risk management activities to reduce the effect of price volatility on our product costs and to ensure the availability of product during periods of short supply. We enter into propane forward and option agreements with third parties, and use fuel oil futures and option contracts traded on the NYMEX, to purchase and sell propane and fuel oil at fixed prices in the future. The majority of the futures, forward and option agreements are used to hedge forecasted purchases of propane or fuel oil and are generally settled at expiration of the contract. Although we use derivative instruments to reduce the effect of price volatility associated with forecasted transactions, we do not use derivative instruments for speculative trading purposes. Risk management activities are monitored by an internal Commodity Risk Management Committee, made up of five members of management, through enforcement of our Hedging and Risk Management Policy and reported to our Audit Committee.
As a result of various market factors during the first half of fiscal 2007, particularly commodity price volatility during the first four months of the fiscal year, we experienced additional margin opportunities due to favorable pricing under certain supply arrangements and from our supply and risk management activities. These market conditions generated additional operating profit of approximately $14.7 million during the year ended September 29, 2007. However, supply and risk management transactions may not always result in increased product margins and there can be no assurance that these favorable market conditions will be present in the future in order to provide the additional margin opportunities realized during fiscal 2007. See Item 7A of this Annual Report.
Critical Accounting Policies and Estimates
Our significant accounting policies are summarized in Note 2, ‘‘Summary of Significant Accounting Policies,’’ included within the Notes to Consolidated Financial Statements section elsewhere in this Annual Report.
Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated, requiring management to make certain assumptions with respect to values or conditions that cannot be known with certainty at the time the financial statements are prepared. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We are also subject to risks and uncertainties that may cause actual results to differ from estimated results. Estimates are used when accounting for depreciation and amortization of long-lived assets, employee benefit plans, self-insurance and litigation reserves, environmental reserves, allowances for doubtful accounts, asset valuation assessments and valuation of derivative instruments. We base our estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known to us. Management has reviewed these critical accounting estimates and related disclosures with the Audit Committee of our Board of Supervisors. We believe that the following are our critical accounting estimates:
Revenue Recognition. Sales of propane, fuel oil and refined fuels are recognized at the time product is delivered to the customer. Revenue from the sale of appliances and equipment is recognized at the time of sale or when installation is complete, as applicable. Revenue from repairs,
26
maintenance and other service activities is recognized upon completion of the service. Revenue from HVAC service contracts is recognized ratably over the service period. Revenue from the natural gas and electricity business is recognized based on customer usage as determined by meter readings, plus an amount for natural gas and electricity delivered but unbilled at the end of each accounting period.
Allowances for Doubtful Accounts. We maintain allowances for doubtful accounts for estimated losses resulting from the inability of our customers to make required payments. We estimate our allowances for doubtful accounts using a specific reserve for known or anticipated uncollectible accounts, as well as an estimated reserve for potential future uncollectible accounts taking into consideration our historical write-offs. If the financial condition of one or more of our customers were to deteriorate resulting in an impairment in their ability to make payments, additional allowances could be required.
Pension and Other Postretirement Benefits. We estimate the rate of return on plan assets, the discount rate to estimate the present value of future benefit obligations and the cost of future health care benefits in determining our annual pension and other postretirement benefit costs. While we believe that our assumptions are appropriate, significant differences in our actual experience or significant changes in market conditions may materially affect our pension and other postretirement benefit obligations and our future expense. See ‘‘Liquidity and Capital Resources – Pension Plan Assets and Obligations’’ below for additional disclosure regarding pension benefits.
Self-Insurance Reserves. Our accrued insurance reserves represent the estimated costs of known and anticipated or unasserted claims under our general and product, workers’ compensation and automobile insurance policies. Accrued insurance provisions for unasserted claims arising from unreported incidents are based on an analysis of historical claims data. For each claim, we record a self-insurance provision up to the estimated amount of the probable claim utilizing actuarially determined loss development factors applied to actual claims data. Our self-insurance provisions are susceptible to change to the extent that actual claims development differs from historical claims development. We maintain insurance coverage wherein our net exposure for insured claims is limited to the insurance deductible, claims above which are paid by our insurance carriers. For the portion of our estimated self-insurance liability that exceeds our deductibles, we record an asset related to the amount of the liability expected to be paid by the insurance companies.
Environmental Reserves. We establish reserves for environmental exposures when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated based upon our evaluation of costs associated with environmental remediation and ongoing monitoring activities. Inherent uncertainties exist in such evaluations due to unknown conditions and changing laws and regulations. These liabilities are adjusted periodically as remediation efforts progress or as additional technical or legal information becomes available. Accrued environmental reserves are exclusive of claims against third parties, and an asset is established where contribution or reimbursement from such third parties, such as governmental agencies, has been agreed and we are reasonably assured of receiving such contribution or reimbursement. Environmental reserves are not discounted.
Goodwill Impairment Assessment. We assess the carrying value of goodwill at a reporting unit level, at least annually, based on an estimate of the fair value of each reporting unit. Fair value of the reporting unit is estimated using discounted cash flow analyses taking into consideration estimated cash flows in a ten-year projection period and a terminal value calculation at the end of the projection period.
Derivative Instruments and Hedging Activities. See Item 7A of this Annual Report for information about accounting for derivative instruments and hedging activities.
Executive Overview of Results of Operations and Financial Condition
During fiscal 2007, we took several steps to deliver increasing value to our Unitholders, streamline our cost structure and further strengthen our balance sheet. Through our efforts over the past two fiscal years to drive operating efficiencies, reduce costs and improve our customer mix, during
27
fiscal 2007 we reported our second consecutive year of record earnings. Net income for fiscal 2007 of $127.3 million, or $3.91 per Common Unit, increased $36.6 million compared to net income of $90.7 million, or $2.84 per Common Unit, in the prior year. EBITDA (as defined and reconciled below) increased $32.5 million, or 19.7%, to $197.8 million in fiscal 2007, compared to EBITDA of $165.3 million in fiscal 2006. Fiscal 2007 included 52 weeks of operations compared to 53 weeks in fiscal 2006.
From a cash flow perspective, despite the sustained period of high commodity prices, we continue to fund working capital requirements from cash on hand and have not borrowed under our working capital facility since April 2006. Additionally, during fiscal 2007 we made a voluntary contribution of $25.0 million to our pension plan from cash on hand in order to fully fund our accumulated benefit obligation which we believe will reduce, if not eliminate, future funding requirements. Even after this voluntary contribution, we ended fiscal 2007 in a strong cash position with approximately $96.6 million in cash on hand, an increase of $36.0 million, or 59.4%, compared to the end of fiscal 2006. On the strength of these earnings and improved cash flows, our Board of Supervisors increased the annualized distribution rate by $0.35 per Common Unit during fiscal 2007 to $3.00 per Common Unit, an increase of 13% compared to the annualized distribution rate at the end of fiscal 2006. Subsequent to the end of fiscal 2007, we also closed on the sale of our Tirzah, South Carolina underground propane storage facility and related 62-mile pipeline (the ‘‘Tirzah Sale’’) for net proceeds of $54.0 million, thus further increasing the cash on hand.
The most significant factor contributing to the growth in earnings was a $49.5 million, or 11.6%, decline in combined operating and general and administrative expenses (excluding certain items of a non-recurring nature in both fiscal years as described below) for fiscal 2007 compared to the prior year, despite a $7.0 million increase in variable compensation costs in line with higher earnings. Since our field and HVAC realignment process began at the end of fiscal 2005, we have eliminated nearly 1,000 positions and retired nearly 1,000 vehicles from our fleet, generating significant savings in our fixed cost structure for the foreseeable future.
In addition, our efforts to improve our customer mix through the strategic exit from certain lower margin business in both the propane and refined fuels segments contributed to the improved year-over-year operating results. Specifically, in the propane segment, we focused on higher margin residential customers and, in several instances, exited certain lower margin commercial, industrial and agricultural customers which accounted for a decrease in volumes sold of approximately 20.9 million gallons compared to the prior year. In the fuel oil and refined fuels segment, our decision to exit certain lower margin diesel and gasoline business resulted in a decrease in volumes sold of approximately 21.7 million gallons in fiscal 2007 compared to the prior year. Overall, retail propane volumes sold during fiscal 2007 decreased 34.3 million gallons, or 7.3%, to 432.5 million gallons compared to 466.8 million gallons in fiscal 2006. Sales of fuel oil and refined fuels decreased 41.1 million gallons, or 28.2%, to 104.5 million gallons in fiscal 2007 compared to 145.6 million gallons in fiscal 2006. Ongoing customer conservation in the sustained high energy price environment, combined with the impact of exiting lower margin business, has had the most significant negative impact on volumes, despite colder average temperatures compared to the prior year. Average temperatures in our service territories were 94% of normal for fiscal 2007 compared to 89% of normal temperatures in the prior year.
In the commodities market, average posted prices for both propane and fuel oil remained high relative to historical trends and, in particular, increased sharply towards the end of fiscal 2007. Average posted prices for propane increased 2.6% and average fuel oil prices decreased 1.2% during fiscal 2007 compared to the prior year. By the end of September 2007 the average posted prices for propane and fuel oil were 41% and 33% higher, respectively, compared to the average posted prices at the end of September 2006. The impact of lower volumes was offset to an extent by higher average margins from an improved customer mix, as well as from additional margin opportunities due to favorable pricing under certain supply arrangements and from hedging and risk management activities, particularly during the first half of fiscal 2007. We attribute approximately $14.7 million of the fiscal 2007 profitability to the favorable supply and market factors. However, supply and risk management
28
activities may not always result in increased product margins and there can be no assurance that the favorable market conditions will be present in the future in order to provide the additional margin contribution realized in fiscal 2007.
Net income and EBITDA for fiscal 2007 included (i) a non-cash pension settlement charge of $3.3 million to accelerate the recognition of actuarial losses in our defined benefit pension plan as a result of the level of lump sum retirement benefit payments made during fiscal 2007; (ii) severance charges of $1.5 million related to positions eliminated in fiscal 2007; (iii) a $2.0 million gain from the recovery of a substantial portion of legal fees associated with our successful defense of a matter following the 1999 acquisition of certain propane assets in North and South Carolina; (iv) gains (reported within discontinued operations) of $1.9 million from the sale and exchange of customer service centers considered to be non-strategic; and (v) a non-cash adjustment to the provision for income taxes – deferred taxes of $3.8 million.
EBITDA and net income for fiscal 2006 were unfavorably impacted by $17.5 million as a result of certain significant items relating mainly to: (i) $6.1 million of restructuring charges primarily related to severance benefits associated with our field realignment and the restructuring of our HVAC business; (ii) incremental professional services fees of $5.0 million associated with the GP Exchange Transaction consummated on October 19, 2006; (iii) a non-cash pension settlement charge of $4.4 million; and (iv) a $2.0 million charge included within cost of products sold to reduce the carrying value of service inventory that will no longer be marketed by our customer service centers as a result of our reorganization.
As we look ahead to fiscal 2008, our anticipated cash requirements include: (i) maintenance and growth capital expenditures of approximately $25.0 million; (ii) approximately $37.0 million of interest and income tax payments; and, (iii) assuming distributions remain at the current level, approximately $98.1 million of distributions to Common Unitholders. Based on our current estimate of our cash position, availability under the Revolving Credit Agreement (unused borrowing capacity under the working capital facility of $124.0 million at September 29, 2007) and expected cash flow from operating activities, we expect to have sufficient funds to meet our current and future obligations.
Results of Operations
Fiscal Year 2007 Compared to Fiscal Year 2006
Fiscal 2007 included 52 weeks of operations compared to 53 weeks in the prior year, which has affected operating results for all categories discussed below.
Revenues
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(Dollars in thousands)
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Fiscal
2007![]()
Fiscal
2006![]()
Decrease
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Percent
Decrease Revenues![]()
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Propane
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$ 1,019,798
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$ 1,081,573
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$ (61,775 )
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(5.7 %) Fuel oil and refined fuels
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262,076
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356,531
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(94,455 )
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(26.5 %) Natural gas and electricity
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94,352
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122,071
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(27,719 )
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(22.7 %) HVAC
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56,519
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87,258
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(30,739 )
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(35.2 %) All other
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6,818
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9,697
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(2,879 )
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(29.7 %) Total revenues
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$ 1,439,563
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$ 1,657,130
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$ (217,567 )
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(13.1 %)
Total revenues decreased $217.6 million, or 13.1%, to $1,439.6 million for the year ended September 29, 2007 compared to $1,657.1 million for the year ended September 30, 2006, driven primarily by lower volumes in each of our operating segments, offset to an extent by the higher average selling prices. As reported by NOAA, average temperatures in our service territories were 6% warmer than normal for fiscal 2007 compared to 11% warmer than normal temperatures in fiscal 2006. Lower volumes, despite the colder average temperatures compared to the prior year, were attributed to ongoing customer conservation driven by high energy costs, our ongoing efforts to improve our customer mix by exiting certain lower margin accounts, as well as the impact of the additional week of operations in the prior year.
29
Revenues from the distribution of propane and related activities of $1,019.8 million for the year ended September 29, 2007 decreased $61.8 million, or 5.7%, compared to $1,081.6 million in the prior year, primarily due to lower volumes, offset to an extent by higher average selling prices. Retail propane gallons sold in fiscal 2007 decreased 34.3 million gallons, or 7.3%, to 432.5 million gallons from 466.8 million gallons in the prior year. Propane volumes sold were negatively affected by customer conservation efforts, and our effort to focus on higher margin residential customers. Average propane selling prices increased 5.1% year-over-year as a result of higher commodity prices for propane and a more favorable customer mix. The average posted price of propane during fiscal 2007 increased 2.6% compared to the average posted prices in the prior year. Additionally, included within the propane segment are revenues from wholesale and risk management activities of $44.8 million for the year ended September 29, 2007, which decreased $29.6 million, or 39.8%, compared to the prior year primarily due to lower risk management activity in the continued high price environment.
Revenues from the distribution of fuel oil and refined fuels of $262.1 million for the year ended September 29, 2007 decreased $94.5 million, or 26.5%, from $356.5 million in the prior year. Fuel oil and refined fuels gallons sold in fiscal 2007 decreased 41.1 million gallons, or 28.2%, to 104.5 million gallons compared to 145.6 million gallons in the prior year. Lower volumes in our fuel oil and refined fuels segment were attributable primarily to our continued efforts to exit certain lower margin gasoline and low sulfur diesel businesses which resulted in an approximate decrease of 21.7 million gallons, or 53% of the total volume decline compared to the prior year. Average selling prices in our fuel oil and refined fuels segment increased 2.4% as a result of the decreased emphasis on lower priced gasoline and diesel businesses. The average posted price of fuel oil during fiscal 2007 decreased 1.2% compared to the average posted prices in the prior year, yet increased sharply during September 2007 compared to the prior year.
Revenues in our natural gas and electricity marketing segment decreased $27.7 million, or 22.7%, to $94.4 million in fiscal 2007 primarily from lower volumes and lower average selling prices for both natural gas and electricity. Revenues in our HVAC segment declined 35.2%, to $56.5 million during fiscal 2007 compared to $87.3 million in the prior year, primarily as a result of the decision during the third quarter of fiscal 2006 to reorganize the HVAC segment and to reduce the level of stand alone HVAC installation activities. The focus of our ongoing service offerings will be in support of our existing propane, refined fuels and natural gas and electricity segments, thus reducing overall HVAC segment revenues.
Cost of Products Sold
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(Dollars in thousands)
![]()
Fiscal
2007![]()
Fiscal
2006![]()
Decrease
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Percent
Decrease Cost of products sold![]()
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Propane
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$ 573,305
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$ 635,365
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$ (62,060 )
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(9.8 %) Fuel oil and refined fuels
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194,213
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272,052
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(77,839 )
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(28.6 %) Natural gas and electricity
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77,116
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102,687
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(25,571 )
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(24.9 %) HVAC
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16,847
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35,972
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(19,125 )
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(53.2 %) All other
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3,937
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5,721
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(1,784 )
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(31.2 %) Total cost of products sold
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$ 865,418
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$ 1,051,797
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$ (186,379 )
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(17.7 %) As a percent of total revenues
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60.1 %
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63.5 %
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The cost of products sold reported in the consolidated statements of operations represents the weighted average unit cost of propane and fuel oil sold, as well as the cost of natural gas and electricity, including transportation costs to deliver product from our supply points to storage or to our customer service centers. Cost of products sold also includes the cost of appliances and related parts sold or installed by our customer service centers computed on a basis that approximates the average cost of the products. Unrealized (non-cash) gains or losses from changes in the fair value of derivative instruments that are not designated as cash flow hedges are recorded in each quarterly reporting
30
period within cost of products sold. Cost of products sold is reported exclusive of any depreciation and amortization; these amounts are reported separately within the consolidated statements of operations.
Cost of products sold decreased $186.4 million, or 17.7%, to $865.4 million for the year ended September 29, 2007, compared to $1,051.8 million in the prior year. The decrease results primarily from the lower sales volumes described above, as well as the impact of various favorable market factors impacting our supply and risk management activities which provided incremental margin opportunities in fiscal 2007. We attribute approximately $14.7 million of the fiscal 2007 margins to these favorable market conditions that may not be present in the future. Additionally, cost of products sold for fiscal 2007 included a $7.6 million unrealized (non-cash) loss representing the net change in fair values of derivative instruments under SFAS No. 133, ‘‘Accounting for Derivative Instruments and Hedging Activities,’’ as amended (‘‘SFAS 133’’), compared to a $14.5 million unrealized (non-cash) gain in the prior year (see Item 7A of this Annual Report for information on our policies regarding the accounting for derivative instruments).
Cost of products sold associated with the distribution of propane and related activities of $573.3 million decreased $62.1 million, or 9.8%, compared to the prior year. Lower sales volumes resulted in a $41.3 million decrease in cost of products sold during fiscal 2007 compared to the prior year, partially offset by higher commodity prices which had an unfavorable impact of $0.7 million compared to the prior year. In addition, the impact of mark-to-market adjustments for derivative instruments under SFAS 133 resulted in a $3.8 million increase in cost of products sold as fiscal 2007 included a $1.9 million unrealized (non-cash) loss, compared to a $1.9 million unrealized (non-cash) gain in the prior year. Wholesale and risk management activities resulted in a $25.6 million decrease in cost of products sold compared to the prior year due to lower risk management activities.
Cost of products sold associated with our fuel oil and refined fuels segment of $194.2 million decreased $77.8 million, or 28.6%, compared to the prior year. Lower sales volumes and lower commodity prices resulted in a decrease in cost of products sold of $80.4 million and $15.8 million, respectively, during fiscal 2007 compared to the prior year. These declines were partially offset by the impact of mark-to-market adjustments for derivative instruments under SFAS 133, which resulted in a $18.3 million increase in cost of products sold as fiscal 2007 included a $5.7 million unrealized (non-cash) loss, compared to a $12.6 million unrealized (non-cash) gain in the prior year.
Cost of products sold in our natural gas and electricity segment of $77.1 million decreased $25.6 million, or 24.9%, compared to prior year primarily due to lower revenues.
Cost of products sold in our HVAC segment of $16.8 million decreased $19.1 million, or 53.2%, compared to prior year primarily due to lower revenues and a charge of $3.5 million in fiscal 2006 to reduce the carrying value of service inventory that is no longer actively marketed by our customer service centers.
For the year ended September 29, 2007, total cost of products sold represented 60.1% of revenues compared to 63.5% in the prior year, primarily as a result of an improved customer mix from our decision to exit certain lower margin customers in both the propane and fuel oil and refined fuels segments, as well as the impact of various favorable market factors impacting our supply and risk management activities and the lower HVAC activities.
Operating Expenses
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(Dollars in thousands)
![]()
Fiscal
2007![]()
Fiscal
2006![]()
Decrease
![]()
Percent
Decrease Operating expenses![]()
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$ 322,852
![]()
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$ 373,305
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$ (50,453 )
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(13.5 %) As a percent of total revenues
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22.4 %
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22.5 %
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All costs of operating our retail distribution and appliance sales and service operations are reported within operating expenses in the consolidated statements of operations. These operating expenses include the compensation and benefits of field and direct operating support personnel, costs of operating and maintaining our vehicle fleet, overhead and other costs of our purchasing, training and safety departments and other direct and indirect costs of operating our customer service centers.
31
Operating expenses of $322.9 million for the year ended September 29, 2007 decreased $50.5 million, or 13.5%, compared to $373.3 million in the prior year, which included an additional week of operations. In fiscal 2007, we realized the full-year effect of the operating efficiencies, lower headcount and lower vehicle count resulting from our field and HVAC reorganizations that began at the end of the third quarter of fiscal 2005 and continued into the beginning of fiscal 2007. The most significant cost savings were experienced in payroll and benefit related expenses which declined $28.5 million, as well as a decrease of $7.1 million in vehicle expenditures and savings in other costs of $16.5 million to operate our customer service centers. These cost savings were offset to an extent by a $2.7 million increase in variable compensation resulting from the improved earnings in fiscal 2007 compared to the prior year. In addition, fiscal 2007 operating expenses include a non-cash pension settlement charge of $3.3 million, which was $1.1 million lower than the prior year charge of $4.4 million, in order to accelerate the recognition of a portion of unrecognized actuarial losses in our defined benefit pension plan as a result of the level of lump sum retirement benefit payments made during each of the respective fiscal years.
General and Administrative Expenses
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(Dollars in thousands)
![]()
Fiscal
2007![]()
Fiscal
2006![]()
Decrease
![]()
Percent
Decrease General and administrative expenses![]()
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$ 56,422
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$ 63,561
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$ (7,139 )
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(11.2 %) As a percent of total revenues
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3.9 %
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3.8 %
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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 $56.4 million for the year ended September 29, 2007 were $7.1 million, or 11.2%, lower compared to $63.6 million in fiscal 2006. The decrease was primarily attributable to a $5.0 million reduction in professional services fees incurred in the prior year associated with the GP Exchange Transaction consummated on October 19, 2006, as well as $4.4 million in higher costs incurred in the prior year associated with our field realignment effort. The reduction in professional services fees also includes a $2.0 million gain from our recovery of a substantial portion of legal fees associated with our successful defense of a matter following the 1999 acquisition of certain propane assets in North and South Carolina. These cost savings were offset to an extent by a $4.3 million increase in variable compensation resulting from the improved earnings in fiscal 2007 compared to the prior year.
Restructuring Charges and Severance Costs. For the year ended September 29, 2007, we recorded a charge of $1.5 million related to severance costs incurred associated with positions eliminated during fiscal 2007 unrelated to a specific plan of restructuring. For the year ended September 30, 2006, we recorded a restructuring charge of $6.1 million related primarily to severance costs incurred to effectuate our field realignment and HVAC restructuring initiatives during fiscal 2006.
Depreciation and Amortization
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(Dollars in thousands)
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Fiscal
2007![]()
Fiscal
2006![]()
Decrease
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Percent
Decrease Depreciation and amortization![]()
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$ 28,790
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$ 32,653
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$ (3,863 )
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(11.8 %) As a percent of total revenues
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2.0 %
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2.0 %
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Depreciation and amortization expense for the year ended September 29, 2007 decreased $3.9 million, or 11.8%, compared to the prior year primarily as a result of lower amortization expense on intangible assets that have been fully amortized, coupled with lower depreciation from asset retirements. Fiscal 2006 depreciation and amortization expense included a $1.1 million asset impairment charge associated with our field realignment efforts, as well as the write-down of certain assets.
32
Interest Expense, net
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(Dollars in thousands)
![]()
Fiscal
2007![]()
Fiscal
2006![]()
Decrease
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Percent
Decrease Interest expense, net![]()
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$ 35,596
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$ 40,680
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$ (5,084 )
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(12.5 %) As a percent of total revenues
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2.5 %
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2.5 %
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Net interest expense decreased $5.1 million, or 12.5%, to $35.6 million in fiscal 2007. During fiscal 2007, there were no borrowings under our working capital facility as seasonal working capital needs have been funded through improved cash flow and cash on hand, resulting in lower interest expense. In the prior year period, average borrowings under our working capital facility amounted to $13.4 million with a peak borrowing level of $84.0 million. Additionally, as a result of increased cash on hand, interest income on invested cash has increased compared to the prior year, thus reducing net interest expense.
Discontinued Operations. During the first quarter of fiscal 2007, in a non-cash transaction, we completed a transaction in which we disposed of nine customer service centers considered to be non-strategic in exchange for three customer service centers of another company located in Alaska. We reported a $1.0 million gain within discontinued operations in the first quarter of fiscal 2007 for the amount by which the fair value of assets relinquished exceeded the carrying value of the assets relinquished. As part of our overall business strategy, we continually monitor and evaluate existing operations in order to identify opportunities to optimize return on assets by selectively divesting operations in slower growing or non-strategic markets. During fiscal 2007, we also sold three customer service centers for net cash proceeds of $1.3 million and recorded a gain on sale of $0.9 million which has been accounted for in accordance with SFAS 144.
On October 2, 2007, we completed the sale of our Tirzah, South Carolina underground granite propane storage cavern, and associated 62-mile pipeline, for approximately $54.0 million in net proceeds. The 57.5 million gallon underground storage cavern is connected to the Dixie Pipeline and provides propane storage for the eastern United States. As part of the agreement, we entered into a long-term storage arrangement with the purchaser of the cavern that will enable us to continue to meet the needs of our retail operations, consistent with past practices. As a result of this sale, a gain of approximately $40.0 million will be reported as a gain from the disposal of discontinued operations in our results for the first quarter of fiscal 2008. The results of operations from the Tirzah facilities have been reported within discontinued operations. Because the transaction closed subsequent to the end of fiscal 2007, our cash on hand at September 29, 2007 does not include the approximate $54.0 million of net proceeds from the sale.
Net Income and EBITDA. We reported net income of $127.3 million, or $3.91 per Common Unit, for the year ended September 29, 2007 compared to net income of $90.7 million, or $2.84 per Common Unit, in the prior year. EBITDA for fiscal 2007 of $197.8 million increased $32.5 million, or 19.7%, compared to EBITDA of $165.3 million in the prior year.
Net income and EBITDA for fiscal 2007 included (i) the non-cash pension settlement charge of $3.3 million; (ii) severance costs of $1.5 million related to positions eliminated; (iii) a gain of $2.0 million from the recovery of a substantial portion of legal fees associated with the successful defense of a matter following the 1999 acquisition of certain propane assets in North and South Carolina; (iv) gains (reported within discontinued operations) of $1.9 million from the sale and exchange of customer service centers considered to be non-strategic; and (v) a non-cash adjustment to the provision for income taxes – deferred taxes of $3.8 million.
By comparison, EBITDA and net income for fiscal 2006 were unfavorably impacted by $17.5 million and $18.6 million, respectively, as a result of certain significant items relating mainly to (i) $6.1 million of restructuring charges primarily related to severance benefits associated with our field realignment and the restructuring of our HVAC business; (ii) incremental professional services fees of $5.0 million associated with the GP Exchange Transaction consummated on October 19, 2006; (iii) a non-cash pension settlement charge of $4.4 million; (iv) a charge of $2.0 million within cost of products sold to reduce the carrying value of service inventory that will no longer be marketed by our
33
customer service centers; and (v) $1.1 million included within depreciation and amortization expense attributable to impairment of assets affected by the field realignment.
EBITDA represents net income before deducting interest expense, income taxes, depreciation and amortization. Our management uses EBITDA as a measure of liquidity and we are including it because we believe that it provides our investors and industry analysts with additional information to evaluate our ability to meet our debt service obligations and to pay our quarterly distributions to holders of our Common Units. In addition, certain of our incentive compensation plans covering executives and other employees utilize EBITDA as the performance target. We use this non-GAAP financial measure in order to assist industry analysts and investors in assessing our liquidity on a year-over-year basis. Moreover, our revolving credit agreement requires us to use EBITDA as a component in calculating our leverage and interest coverage ratios. EBITDA is not a recognized term under GAAP and should not be considered as an alternative to net income or net cash provided by operating activities determined in accordance with GAAP. Because EBITDA as determined by us excludes some, but not all, items that affect net income, it may not be comparable to EBITDA or similarly titled measures used by other companies.
The following table sets forth (i) our calculations of EBITDA and (ii) a reconciliation of EBITDA, as so calculated, to our net cash provided by operating activities:
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Year Ended (Dollars in thousands)
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September 29,
2007![]()
September 30,
2006 Net income (loss)![]()
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$ 127,287
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$ 90,740
Add:
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Provision for income taxes
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5,653
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764
Interest expense, net
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35,596
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40,680
Depreciation and amortization – continuing operations
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28,790
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32,653
Depreciation and amortization – discontinued operations
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452
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498
EBITDA
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197,778
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165,335
Add (subtract):
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Provision for income taxes – current
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(1,853 )
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(764 ) Interest expense, net
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(35,596 )
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(40,680 ) Compensation cost recognized under Restricted Unit Plan
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3,014
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2,221
Gain on disposal of property, plant and equipment, net
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(2,782 )
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(1,000 ) Gain on disposal of discontinued operations
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(1,887 )
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—
Pension settlement charge
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3,269
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4,437
Changes in working capital and other assets and liabilities
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(15,986 )
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40,772
Net cash provided by operating activities
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$ 145,957
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$ 170,321
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Fiscal Year 2006 Compared to Fiscal Year 2005
Fiscal 2006 includes 53 weeks of operations compared to 52 weeks in the prior year, which has affected operating results for all categories discussed below.
34
Revenues
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(Dollars in thousands)
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Fiscal
2006![]()
Fiscal
2005![]()
Increase /
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Percent
Increase /
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Propane
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$ 1,081,573
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$ 965,264
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$ 116,309
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12.0 % Fuel oil and refined fuels
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356,531
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431,223
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(74,692 )
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(17.3 %) Natural gas and electricity
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122,071
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102,803
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19,268
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18.7 % HVAC
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87,258
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106,115
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(18,857 )
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(17.8 %) All other
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9,697
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10,150
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(453 )
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(4.5 %) Total revenues
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$ 1,657,130
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$ 1,615,555
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$ 41,575
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2.6 %
Total revenues increased $41.5 million, or 2.6%, to $1,657.1 million for the year ended September 30, 2006 compared to $1,615.6 million for the year ended September 24, 2005, driven primarily by higher average selling prices resulting from significantly higher commodity prices, offset to an extent by lower volumes in our propane and fuel oil and refined fuels segments. As reported by NOAA, average temperatures in our service territories were 11% warmer than normal for fiscal 2006 compared to 6% warmer than normal temperatures in fiscal 2005. While the fiscal 2006 heating season began with temperatures that were 5% warmer than normal in the first quarter, significantly warmer than normal temperatures, particularly during the critical heating months of January and February 2006 which were 20% warmer than normal, had a significant negative impact on volumes sold. In the commodities markets, the high propane and fuel oil prices experienced throughout fiscal 2005 continued into fiscal 2006, thus continuing to negatively impact volumes as a result of customer conservation.
Revenues from the distribution of propane and related activities of $1,081.6 million for the year ended September 30, 2006 increased $116.3 million, or 12.0%, compared to $965.3 million in the prior year, primarily due to the impact of higher average selling prices in line with significantly higher product costs, offset to an extent by the impact of lower volumes. Retail propane gallons sold in fiscal 2006 decreased 49.2 million gallons, or 9.5%, to 466.8 million gallons from 516.0 million gallons in the prior year. Propane volumes sold were negatively affected by the impact of warmer weather, customer conservation efforts, and our effort to focus on higher margin residential customers. Average propane selling prices increased 19.9% as a result of higher commodity prices for propane. The average posted price of propane during fiscal 2006 increased 21.8% compared to the average posted prices in the prior year. Additionally, included within the propane segment are revenues from wholesale and risk management activities of $74.4 million for the year ended September 30, 2006 which was comparable to the prior year.
Revenues from the distribution of fuel oil and refined fuels of $356.5 million for the year ended September 30, 2006 decreased $74.7 million, or 17.3%, from $431.2 million in the prior year. Sales of fuel oil and refined fuels amounted to 145.6 million gallons during fiscal 2006 compared to 244.5 million gallons in the prior year, a decrease of 98.9 million gallons, or 40.4%. Lower volumes in our fuel oil and refined fuels segment were attributable primarily to our continued efforts to exit certain lower margin diesel and gasoline businesses which resulted in an approximate decrease of 51.8 million gallons compared to the prior year, combined with the impact of high prices on fuel oil volumes, as well as the impact on volumes from the decision to eliminate the 2005 fiscal year fuel oil ceiling program (‘‘Ceiling Program’’). Average selling prices in our fuel oil and refined fuels segment increased 38.8% as a result of higher fuel oil commodity prices, coupled with the decreased emphasis on lower priced diesel and gasoline businesses and the shift in our pricing strategy at the field level following the elimination of the restrictions from the Ceiling Program. The average posted price of fuel oil during fiscal 2006 increased 21.4% compared to the average posted prices in the prior year.
Revenues for the year ended September 30, 2006 were favorably impacted by an 18.7% increase in our natural gas and electricity segment, which increased to $122.1 million from $102.8 million in the prior year, primarily as a result of a rise in electricity volumes coupled with increases in average selling prices for natural gas and electricity in line with higher commodity prices. Revenues in our
35
HVAC segment declined 17.8%, to $87.3 million during fiscal 2006 compared to $106.1 million in the prior year, primarily as a result of the decision during the third quarter of fiscal 2006 to reorganize the HVAC segment and to reduce the level of HVAC installation activities. The focus of our ongoing service offerings will be in support of our existing propane, refined fuels and natural gas and electricity segments, thus reducing overall HVAC segment revenues.
Cost of Products Sold
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(Dollars in thousands)
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Fiscal
2006![]()
Fiscal
2005![]()
Increase /
(Decrease)![]()
Percent
Increase /
(Decrease) Cost of products sold![]()
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Propane
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$ 635,365
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$ 545,677
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$ 89,688
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16.4 % Fuel oil and refined fuels
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272,052
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385,501
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(113,449 )
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(29.4 %) Natural gas and electricity
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102,687
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90,461
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12,226
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13.5 % HVAC
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35,972
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42,650
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(6,678 )
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(15.7 %) All other
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5,721
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5,456
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265
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4.9 % Total cost of products sold
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$ 1,051,797
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$ 1,069,745
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$ (17,948 )
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(1.7 %) As a percent of total revenues
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63.5 %
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66.2 %
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Cost of products sold decreased $17.9 million to $1,051.8 million for the year ended September 30, 2006, compared to $1,069.7 million in the prior year. The decrease results primarily from the lower sales volumes described above, offset to an extent by higher commodity prices for propane and fuel oil. Cost of products sold for fiscal 2006 include a $14.5 million unrealized (non-cash) gain representing the net change in fair values of derivative instruments under SFAS No. 133, ‘‘Accounting for Derivative Instruments and Hedging Activities,’’ as amended by SFAS Nos. 137, 138, 149 and 155 (‘‘SFAS 133’’), compared to a $2.5 million unrealized (non-cash) loss in the prior year (see Item 7A of this Annual Report for information on our policies regarding the accounting for derivative instruments).
Cost of products sold associated with the distribution of propane and related activities of $635.4 million increased $89.7 million, or 16.4%, compared to the prior year. Higher propane prices resulted in a $106.9 million increase in cost of products sold during fiscal 2006 compared to the prior year, partially offset by decreased propane volumes which had an impact of $48.0 million. Wholesale and risk management activities resulted in a $28.0 million increase in cost of products sold compared to the prior year.
Cost of products sold associated with our fuel oil and refined fuels segment of $272.1 million decreased $113.4 million, or 29.4%, compared to the prior year. Lower sales volumes resulted in a $154.9 million decrease in cost of products sold during fiscal 2006 compared to the prior year, partially offset by higher commodity prices which had an impact of $56.5 million compared to the prior year. Cost of products sold as a percentage of revenues in our fuel oil and refined fuels segment decreased from 89.4% during fiscal 2005 to 76.3% in fiscal 2006 primarily as a result of the elimination of the Ceiling Program which had the effect of restricting fuel oil margin opportunities in fiscal 2005. The Ceiling Program primarily affected deliveries from February through April 2005 as a result of the decision not to hedge the program; however, the inability to pass on the significant rise in the commodity prices throughout fiscal 2005 significantly affected margin opportunities. The lost margin opportunity from this fuel oil Ceiling Program had an estimated negative impact of $21.5 million on fiscal 2005 operating margins in the fuel oil and refined fuels segment. By eliminating this pricing program beginning in fiscal 2006, we no longer incur the costs of hedging deliveries made under the program and we have been successful in implementing our market-based pricing strategies in our field operations, without significant customer losses.
The increase in revenues attributable to our natural gas and electricity segment had a $12.2 million impact on cost of products sold for the year ended September 30, 2006 compared to the prior year. Cost of products sold in our HVAC segment declined $10.2 million as a result of lower
36
revenues, partially offset by a charge of $3.5 million to reduce the carrying value of inventory that will no longer be actively marketed by our customer service centers.
For the year ended September 30, 2006, total cost of products sold represented 63.3% of revenues compared to 66.0% in the prior year, primarily as a result of the improved pricing strategy in the fuel oil operations following the elimination of the Ceiling Program, as well as the improved customer mix from our decision to exit certain lower margin customers in both the propane and fuel oil and refined fuels segments.
Operating Expenses
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(Dollars in thousands)
![]()
Fiscal
2006![]()
Fiscal
2005![]()
Decrease
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Percent
Decrease Operating expenses![]()
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$ 373,305
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$ 392,335
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$ (19,030 )
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(4.9 %) As a percent of total revenues
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22.5 %
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24.3 %
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Operating expenses of $373.3 million for the year ended September 30, 2006 decreased $19.0 million, or 4.9%, compared to $392.3 million in the prior year, primarily as a result of cost savings achieved through the aforementioned field realignment efforts and restructuring of our HVAC service offerings. During the fourth quarter of fiscal 2005, we initiated plans to realign our field operations and, as a second phase of our field realignment, during the third quarter of fiscal 2006 we initiated plans to restructure our HVAC service offerings by reducing our HVAC installation activities. These efforts have significantly restructured our operating footprint and reduced our cost structure through the elimination of more than 400 positions and the retirement of nearly 700 vehicles from our fleet through the creation of routing efficiencies, generating significant savings in our fixed cost structure. As a result, payroll and benefit related expenses declined $16.6 million and savings in other operating expenses amounted to $10.6 million. In addition, bad debt expense decreased $2.4 million from improved collection efforts. These cost savings were offset to an extent by a $6.2 million increase in variable compensation resulting from the improved earnings in fiscal 2006 compared to the prior year. Additionally, fiscal 2006 operating expenses include a $4.4 million non-cash pension settlement charge in order to accelerate the recognition of a portion of unrecognized actuarial losses in our defined benefit pension plan as a result of the level of lump sum benefit payments made during fiscal 2006 from the reduction in headcount.
General and Administrative Expenses
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(Dollars in thousands)
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Fiscal
2006![]()
Fiscal
2005![]()
Increase
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Percent
Increase General and administrative expenses![]()
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$ 63,561
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$ 47,191
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$ 16,370
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34.7 % As a percent of total revenues
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3.8 %
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2.9 %
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General and administrative expenses of $63.6 million for the year ended September 30, 2006 were $16.4 million, or 34.7%, higher compared to $47.2 million in fiscal 2005. The increase was primarily attributable to a $9.2 million increase in variable compensation in line with increased earnings, incremental professional services fees of $5.0 million associated with the GP Exchange Transaction consummated on October 19, 2006 and an increase of $2.2 million in other expenses associated with our field realignment efforts.
Restructuring Charges and Severance Costs and Impairment of Goodwill. For the year ended September 30, 2006, we recorded a restructuring charge of $6.1 million related primarily to severance costs incurred to effectuate our field realignment and HVAC restructuring initiatives during fiscal 2006 resulting in the elimination of more than 400 positions. During fiscal 2005, we recorded a $2.8 million restructuring charge related primarily to employee termination costs incurred as a result of actions taken during fiscal 2005.
During fiscal 2005 we recorded a non-cash charge of $0.7 million related to the impairment of goodwill associated with our HVAC segment as a result of our annual assessment of the anticipated future cash flows from that segment.
37
Depreciation and Amortization
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(Dollars in thousands)
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Fiscal
2006![]()
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2005![]()
Decrease
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Percent
Decrease Depreciation and amortization![]()
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$ 32,653
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$ 37,260
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$ (4,607 )
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(12.4 %) As a percent of total revenues
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2.0 %
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2.3 %
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Depreciation and amortization expense for the year ended September 30, 2006 decreased $4.6 million, or 12.4%, compared to the prior year primarily as a result of lower amortization expense on intangible assets that have been fully amortized, coupled with lower deprecation from asset retirements. Fiscal 2006 depreciation and amortization expense included a $1.1 million asset impairment charge associated with our field realignment efforts, as well as the write-down of certain assets in the all other business segment, compared to a $1.2 million impairment charge included in depreciation and amortization expense in the prior year.
Interest Expense, net
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(Dollars in thousands)
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Fiscal
2006![]()
Fiscal
2005![]()
Increase
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Percent
Increase Interest expense, net![]()
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$ 40,680
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$ 40,374
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$ 306
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0.8 % As a percent of total revenues
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2.5 %
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2.5 %
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Net interest expense increased $0.3 million, or 0.8%, to $40.7 million in fiscal 2006 as a result of increased borrowings under our working capital facility during the fiscal 2006 heating season compared to the prior year.
Discontinued Operations. Discontinued operations reflect the income associated with the assets sold in the Tirzah Sale of $2.4 million and $2.8 million for fiscal year 2006 and 2005, respectively. During fiscal 2005, we also recorded a gain on sale of $1.0 million to reflect the finalization of certain purchase price adjustments with the buyer of the customer service centers sold in fiscal 2004.
Net Income (Loss) and EBITDA. We reported net income of $90.7 million for the year ended September 30, 2006 compared to a net loss of $8.1 million in the prior year. EBITDA for fiscal 2006 of $165.3 million increased $58.2 million, or 54.3%, compared to Adjusted EBITDA of $107.1 million in the prior year.
EBITDA and net income for fiscal 2006 were unfavorably impacted by $17.5 million and $18.6 million, respectively, as a result of certain significant items relating mainly to (i) $6.1 million of restructuring charges primarily related to severance benefits associated with our field realignment and the restructuring of our HVAC business; (ii) incremental professional services fees of $5.0 million associated with the GP Exchange Transaction consummated on October 19, 2006; (iii) a non-cash pension settlement charge of $4.4 million; (iv) a charge of $2.0 million within cost of products sold to reduce the carrying value of inventory that will no longer be marketed by our customer service centers; and (v) $1.1 million included within depreciation and amortization expense attributable to impairment of assets affected by the field realignment.
By comparison, Adjusted EBITDA and net loss for fiscal 2005 were unfavorably impacted by $3.5 million and $40.9 million, respectively, as a result of certain significant items relating mainly to (i) a $36.2 million loss on debt extinguishment associated with our March 31, 2005 debt refinancing; (ii) a $2.8 million restructuring charge attributable primarily to severance associated with the realignment of our field operations; (iii) a $0.7 million charge attributable to impairment of goodwill associated with our HVAC segment; (iv) a $0.8 million charge included within amortization expense attributable to the impairment of other intangible assets in our HVAC segment; and (v) $0.4 million included within depreciation expense attributable to impairment of assets affected by the field realignment. In addition to the non-recurring items impacting fiscal 2005 results, the most significant negative impact on operating results was from the approximate $21.5 million impact on margin opportunities in our fuel oil business from the Ceiling Program.
EBITDA represents net income before deducting interest expense, income taxes, depreciation and amortization. Our management uses EBITDA as a measure of liquidity and we are including it
38
because we believe that it provides our investors and industry analysts with additional information to evaluate our ability to meet our debt service obligations and to pay our quarterly distributions to holders of our Common Units. In addition, certain of our incentive compensation plans covering executives and other employees utilize EBITDA as the performance target. We use the term Adjusted EBITDA to reflect the presentation of EBITDA for the year ended September 24, 2005 exclusive of the impact of the non-cash charge for loss on debt extinguishment in the amount of $36.2 million. We use this non-GAAP financial measure in order to assist industry analysts and investors in assessing our liquidity on a year-over-year basis. Moreover, our revolving credit agreement requires us to use EBITDA or Adjusted EBITDA as a component in calculating our leverage and interest coverage ratios. EBITDA and Adjusted EBITDA are not recognized terms under GAAP and should not be considered as alternatives to net income or net cash provided by operating activities determined in accordance with GAAP. Because EBITDA as determined by us excludes some, but not all, items that affect net income, it may not be comparable to EBITDA or similarly titled measures used by other companies.
The following table sets forth (i) our calculations of EBITDA and Adjusted EBITDA and (ii) a reconciliation of EBITDA and Adjusted EBITDA, as so calculated, to our net cash provided by operating activities:
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Year Ended (Dollars in thousands)
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September 30,
2006![]()
September 24,
2005 Net income (loss)![]()
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$ 90,740
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$ (8,076 ) Add:
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Provision for income taxes
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764
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803
Interest expense, net
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40,680
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40,374
Depreciation and amortization – continuing operations
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32,653
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37,260
Depreciation and amortization – discontinued operations
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498
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502
EBITDA
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165,335
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70,863
Loss on debt extinguishment
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—
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36,242
Adjusted EBITDA
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165,335
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107,105
Add (subtract):
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Provision for income taxes
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(764 )
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(803 ) Loss on debt extinguishment
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—
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(36,242 ) Interest expense, net
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(40,680 )
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(40,374 ) Compensation cost recognized under Restricted Unit Plan
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2,221
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1,805
Gain on disposal of property, plant and equipment, net
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(1,000 )
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(2,043 ) Gain on disposal of discontinued operations
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—
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(976 ) Pension settlement charge
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4,437
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—
Changes in working capital and other assets and liabilities
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40,772
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10,533
Net cash provided by operating activities
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$ 170,321
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$ 39,005
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Liquidity and Capital Resources
Analysis of Cash Flows
Operating Activities. Net cash provided by operating activities for the year ended September 29, 2007 amounted to $146.0 million, a decrease of $24.3 million compared to $170.3 million in the prior year. The decrease was attributable to a $41.7 million increase in working capital and a $15.0 million increase in voluntary contributions to our defined benefit pension plan compared to the prior year, partially offset by $32.4 million in increased earnings, after adjusting for non-cash items in both periods (depreciation, amortization compensation costs recognized under our
39
Restricted Unit Plan, gains on disposal of assets, pension settlement charges and deferred tax provision). The fiscal 2007 voluntary pension plan contribution of $25.0 million was made to fully fund our estimated accumulated benefit obligation, thus substantially reducing, if not eliminating, our future funding requirements. As of September 29, 2007, the funded status of our defined benefit pension plan was $5.5 million, or 103% funded.
In fiscal 2006, net cash provided by operating activities increased $131.3 million to $170.3 million, compared to $39.0 million in fiscal 2005. The increase was attributable to an $81.0 million decreased investment in working capital in comparison to the prior year, particularly in decreased accounts receivable balances as a result of steps taken during fiscal 2006 to improve collection efforts, coupled with $64.1 million higher income, after adjusting for non-cash items in both periods (depreciation, amortization, pension settlement charge, loss on debt extinguishment, impairment of goodwill and gains on disposal of assets and customer service centers); offset to an extent by a decrease in other long-term assets and liabilities of $13.8 million.
Investing Activities. Net cash used in investing activities of $19.7 million for the year ended September 29, 2007 consisted of capital expenditures of $26.8 million (including $10.0 million for maintenance expenditures and $16.8 million to support the growth of operations), offset by net proceeds of $5.8 million from the sale of property, plant and equipment and proceeds from the sale of certain customer service centers of $1.3 million. Capital spending in fiscal 2007 increased $3.7 million, or 16.0%, compared to fiscal 2006 primarily as a result of spending on information technology to finalize the integration of systems from the Agway Acquisition, as well as the timing of capital spending for our field realignment efforts, particularly to integrate certain customer service center locations.
Net cash used in investing activities of $19.1 million for the year ended September 30, 2006 consisted of capital expenditures of $23.1 million (including $11.2 million for maintenance expenditures and $11.9 million to support the growth of operations), offset by net proceeds of $4.0 million from the sale of property, plant and equipment. Capital spending in fiscal 2006 decreased $6.2 million, or 21.2%, compared to fiscal 2005 primarily as a result of (i) efforts to consolidate existing storage assets for better utilization in conjunction with our fiscal 2006 field realignment efforts thereby reducing fiscal 2006 spending needs; and (ii) a reduction from fiscal 2005 spending on information technology for the integration of Agway Energy.
Financing Activities. Net cash used in financing activities for the year ended September 29, 2007 of $90.3 million reflects quarterly distributions to Common Unitholders at a rate of $0.6625 per Common Unit in respect of the fourth quarter of fiscal 2006, at a rate of $0.6875 per Common Unit in respect of the first quarter of fiscal 2007, at a rate of $0.70 per Common Unit in respect of the second quarter of fiscal 2007 and at a rate of $0.7125 per Common Unit in respect of the third quarter of fiscal 2007. There were no borrowings under our working capital facility during fiscal 2007, nor have there been any borrowings since April 2006.
Net cash used in financing activities for the year ended September 30, 2006 of $105.1 million reflects the repayment of short-term borrowings of $26.8 million under our Revolving Credit Agreement and quarterly distributions to Common Unitholders and the General Partner at a rate of $0.6125 per Common Unit in respect of the fourth quarter of fiscal 2005 and the first and second quarters of fiscal 2006 and at a rate of $0.6375 per Common Unit in respect of the third quarter of fiscal 2006 totaling $77.8 million. This distribution amount includes a $0.3 million payment made to the General Partner reflecting a true-up of previous underpayments resulting from an error in the computation of quarterly cash distributions to the General Partner. During fiscal 2006, borrowings under the working capital facility reached $84.0 million during the peak heating season, which was fully repaid by the end of April 2006.
Summary of Long-Term Debt Obligations and Revolving Credit Lines
Our long-term borrowings and revolving credit lines consist of $425.0 million in 6.875% senior notes due December 2013 (the ‘‘2003 Senior Notes’’) and a Revolving Credit Agreement at the Operating Partnership level which provides a five-year $125.0 million term loan due March 31, 2010
40
(the ‘‘Term Loan’’) and a separate working capital facility which provides available credit up to $175.0 million. There were no outstanding borrowings under the working capital facility as of September 29, 2007. There have been no borrowings under our working capital facility since April 2006. We have standby letters of credit issued under the working capital facility of the Revolving Credit Agreement in the aggregate amount of $51.0 million in support of retention levels under our self-insurance programs and certain lease obligations. Therefore, as of September 29, 2007 we had available borrowing capacity of $124.0 million under the working capital facility of the Revolving Credit Agreement. Additionally, under the third amendment to the Revolving Credit Agreement our Operating Partnership is authorized to incur additional indebtedness of up to $10.0 million in connection with capital leases and up to $20.0 million in short-term borrowings during the period from December 1 to April 1 in each fiscal year in order to meet working capital needs during periods of peak demand, if necessary. Because of our operating results and cash flow, we did not make any such short-term borrowings during fiscal 2007.
The 2003 Senior Notes mature on December 15, 2013 and require semi-annual interest payments. We are permitted to redeem some or all of the 2003 Senior Notes any time on or after December 15, 2008 at redemption prices specified in the indenture governing the 2003 Senior Notes. In addition, the 2003 Senior Notes have a change of control provision that would require us to offer to repurchase the notes at 101% of the principal amount repurchased, if the holders of the notes elected to exercise the right of repurchase. Borrowings under the Revolving Credit Agreement, including the Term Loan, bear interest at a rate based upon either LIBOR or Wachovia National Bank’s prime rate plus, in each case, the applicable margin. An annual facility fee ranging from 0.375% to 0.50%, based upon certain financial tests, is payable quarterly whether or not borrowings occur.
In connection with the Term Loan, our Operating Partnership also entered into an interest rate swap contract with a notional amount of $125.0 million with the issuing lender. Effective March 31, 2005 through March 31, 2010, our Operating Partnership will pay a fixed interest rate of 4.66% to the issuing lender on the notional principal amount of $125.0 million, effectively fixing the LIBOR portion of the interest rate at 4.66%. In return, the issuing lender will pay to our Operating Partnership a floating rate, namely LIBOR, on the same notional principal amount. The applicable margin above LIBOR, as defined in the Revolving Credit Agreement, will be paid in addition to this fixed interest rate of 4.66%.
Under the Revolving Credit Agreement, our Operating Partnership must maintain a leverage ratio (the ratio of total debt to EBITDA) of less than 4.0 to 1 and an interest coverage ratio (the ratio of EBITDA to interest expense) of greater than 2.5 to 1 at the Partnership level. The Revolving Credit Agreement and the 2003 Senior Notes both contain various restrictive and affirmative covenants applicable to our Operating Partnership and us, respectively. These covenants include (i) restrictions on the incurrence of additional indebtedness and (ii) restrictions on certain liens, investments, guarantees, loans, advances, payments, mergers, consolidations, distributions, sales of assets and other transactions. We were in compliance with all covenants and terms of all of our debt agreements as of September 29, 2007.
Partnership Distributions
We are required to make distributions in an amount equal to all of our Available Cash, as defined in the Third Amended and Restated Partnership Agreement, as amended, no more than 45 days after the end of each fiscal quarter to holders of record on the applicable record dates. Available Cash, as defined in the Partnership Agreement, generally means all cash on hand at the end of the respective fiscal quarter less the amount of cash reserves established by the Board of Supervisors in its reasonable discretion for future cash requirements. These reserves are retained for the proper conduct of our business, the payment of debt principal and interest and for distributions during the next four quarters. The Board of Supervisors reviews the level of Available Cash on a quarterly basis based upon information provided by management. As a result of the GP Exchange Transaction, all IDRs formerly held by the General Partner have been cancelled and the General Partner is not entitled to receive any cash distributions in respect of its general partner interests. Accordingly, beginning with
41
the quarterly distribution paid on November 14, 2006 in respect of the fourth quarter of fiscal 2006, 100% of all cash distributions are paid to the holders of Common Units, including the 2.3 million Common Units issued in the GP Exchange Transaction.
On October 25, 2007, we announced a quarterly distribution of $0.75 per Common Unit, or $3.00 on an annualized basis, in respect of the fourth quarter of fiscal 2007 payable on November 13, 2007 to holders of record on November 6, 2007. This quarterly distribution included an increase of $0.0375 per Common Unit, or $0.15 per Common Unit on an annualized basis, from the previous quarterly distribution rate representing the fifteenth increase since our recapitalization in 1999 and a 13% increase in the quarterly distribution rate since the fourth quarter of the prior year.
Pension Plan Assets and Obligations
Our defined benefit pension plan was frozen to new participants effective January 1, 2000 and, in furtherance of our effort to minimize future increases in our benefit obligations, effective January 1, 2003, all future service credits were eliminated. Therefore, eligible participants will receive interest credits only toward their ultimate defined benefit under the defined benefit pension plan. There were no minimum funding requirements for the defined benefit pension plan during fiscal 2007, 2006 or 2005. During 2007, we made a voluntary cash contribution from cash on hand of $25.0 million to our defined benefit pension plan in order to fully fund our estimated accumulated benefit obligation, thus substantially reducing, if not eliminating, our future funding requirements. As a result of our voluntary contributions and improved asset returns in our pension asset portfolio during the last several years, the fair value of plan assets exceeded the accumulated benefit obligation of the defined benefit pension plan by $5.5 million as of September 29, 2007. This overfunded position resulted in the elimination of the additional minimum liability of $63.5 million with a corresponding increase to accumulated other comprehensive loss, a component of partners’ capital.
At the end of fiscal 2007, we adopted SFAS No. 158, ‘‘Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – An Amendment of FASB Statements No. 87, 88, 103 and 132R’’ (‘‘SFAS 158’’), which requires companies to recognize the funded status of pension and other postretirement benefit plans as an asset or liability on sponsoring employers’ balance sheets and to recognize changes in the funded status in comprehensive income (loss) in the year the changes occur. This adoption resulted in a $48.0 million reduction to the prepaid pension asset and a $5.0 million decrease to accrued postretirement liability, with the net amount of $43.0 million recorded as a reduction in the net assets of the Partnership to accumulated other comprehensive loss. As of September 29, 2007, the fair value of plan assets exceeded the projected benefit obligation of the defined benefit pension plan by $5.5 million, which was recognized on the balance sheet as an asset in accordance with SFAS 158.
During fiscal 2007, lump sum benefit payments of $10.8 million exceeded the combined service and interest costs of the net periodic pension cost. As a result, pursuant to SFAS No. 88 ‘‘Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,’’ we recorded a non-cash settlement charge of $3.3 million in order to accelerate recognition of a portion of cumulative unrecognized losses in the defined benefit pension plan. These unrecognized losses were previously accumulated as a reduction to partners’ capital and were being amortized to expense as part of our net periodic pension cost in accordance with SFAS No. 87 ‘‘Employers’ Accounting for Pensions.’’ A similar non-cash pension settlement charge of $4.4 million was recorded in fiscal 2006 as a result of the level of lump sum benefit payments. Additional pension settlement charges may be required in future periods depending on the level of lump sum benefit payments.
The Partnership’s investment policies and strategies, as set forth in the Investment Management Policy and Guidelines, are monitored by a Benefits Committee comprised of five members of management. During fiscal 2007, the Benefits Committee proposed and the Board of Supervisors approved contributions to the plan in order to fully fund the accumulated benefit obligation, as described above, and to change the plan’s asset allocation to reduce investment risk and more closely match the asset mix to the future cash requirements of the plan. The implementation of this strategy
42
resulted in the $25.0 million voluntary contribution described above, and a change in the asset allocation to reflect a greater concentration of fixed income securities.
There can be no assurance that future declines in capital markets, or interest rates, will not have an adverse impact on our results of operations or cash flow. However, with the overfunded status of the plan, coupled with the shift in investment strategy to a higher concentration of fixed income securities, we expect over the long-term that the returns on plan assets should match increases in the accumulated benefit obligation resulting from interest credits, this maintaining a fully funded status. For purposes of computing the actuarial valuation of projected benefit obligations, we increased the discount rate assumption from 5.50% as of September 30, 2006 to 6.00% as of September 29, 2007 to reflect current market expectations related to long-term interest rates and the projected duration of our pension obligations based on a benchmark index with similar characteristics as the expected cash flow requirements of our defined benefit pension plan over the long-term. Additionally, for purposes of the computation of the net periodic pension cost for fiscal 2007, 2006 and 2005 we assumed increased long-term rates of return on plan assets of 8.00%, 8.00% and 7.50%, respectively, based on the investment mix of our pension asset portfolio, historical asset performance and expectations for future performance. For purposes of the computation of the net periodic pension cost for fiscal 2008, we expect the rate of return on plan assets will be reduced to reflect the higher concentration of fixed income securities. Based on information provided by our actuaries, we do not project any future funding requirements.
We also provide postretirement health care and life insurance benefits for certain retired employees. Partnership employees who were hired prior to July 1993 and retired prior to March 1998 are eligible for such benefits if they reached a specific retirement age while working for the Partnership. Effective January 1, 2000, we terminated our postretirement benefit plan for all eligible employees retiring after March 1, 1998. All active and eligible employees who were to receive benefits under the postretirement plan subsequent to March 1, 1998 were provided an increase to their accumulated benefits under the defined benefit pension plan. Our postretirement health care and life insurance benefit plans are unfunded.
Long-Term Debt Obligations and Operating Lease Obligations
Contractual Obligations
Long-term debt obligations and future minimum rental commitments under noncancelable operating lease agreements as of September 29, 2007 are due as follows:
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![]()
(Dollars in thousands)
![]()
Fiscal
2008![]()
Fiscal
2009![]()
Fiscal
2010![]()
Fiscal
2011![]()
Fiscal 2012
and
thereafter![]()
Total Long-term debt
![]()
![]()
$ —
![]()
![]()
![]()
$ —
![]()
![]()
![]()
$ 125,000
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![]()
![]()
$ —
![]()
![]()
![]()
$ 425,000
![]()
![]()
![]()
$ 550,000
Future interest payments
![]()
![]()
![]()
38,606
![]()
![]()
![]()
![]()
38,606
![]()
![]()
![]()
![]()
36,259
![]()
![]()
![]()
![]()
29,219
![]()
![]()
![]()
![]()
73,048
![]()
![]()
![]()
![]()
215,738
Operating leases
![]()
![]()
![]()
12,903
![]()
![]()
![]()
![]()
9,455
![]()
![]()
![]()
![]()
6,798
![]()
![]()
![]()
![]()
4,342
![]()
![]()
![]()
![]()
3,114
![]()
![]()
![]()
![]()
36,612
Total debt obligations, cash interest and lease commitments
![]()
![]()
$ 51,509
![]()
![]()
![]()
$ 48,061
![]()
![]()
![]()
$ 168,057
![]()
![]()
![]()
$ 33,561
![]()
![]()
![]()
$ 501,162
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![]()
![]()
$ 802,350
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Additionally, we have standby letters of credit in the aggregate amount of $51.0 million, in support of retention levels under our casualty insurance programs and certain lease obligations, which expire periodically through October 25, 2008.
Operating Leases
We lease certain property, plant and equipment for various periods under noncancelable operating leases, including approximately 53% of our vehicle fleet, approximately 25% of our customer service centers and portions of our information systems equipment. Rental expense under operating leases was $19.6 million, $27.2 million and $28.6 million for fiscal 2007, 2006 and 2005, respectively. Future minimum rental commitments under noncancelable operating lease agreements as of September 29, 2007 are presented in the table above.
43
Off-Balance Sheet Arrangements
Guarantees
We have residual value guarantees associated with certain of our operating leases, related primarily to transportation equipment, with remaining lease periods scheduled to expire periodically through fiscal 2014. Upon completion of the lease period, we guarantee that the fair value of the equipment will equal or exceed the guaranteed amount, or we will pay the lessor the difference. Although the fair value of equipment at the end of its lease term has historically exceeded the guaranteed amounts, the maximum potential amount of aggregate future payments we could be required to make under these leasing arrangements, assuming the equipment is deemed worthless at the end of the lease term, is approximately $15.3 million. The fair value of residual value guarantees for outstanding operating leases was $-0- as of September 29, 2007 and September 30, 2006.
Recently Issued Accounting Standards
In February 2007, the Financial Accounting Standards Board (‘‘FASB’’) issued SFAS No. 159, ‘‘The Fair Value Option for Financial Assets and Financial Liabilities’’ (‘‘SFAS 159’’). Under SFAS 159, entities may elect to measure specified financial instruments and warranty and insurance contracts at fair value on a contract-by-contract basis, with changes in fair value recognized in earnings each reporting period. SFAS 159 is effective for fiscal years beginning after November 15, 2007, which will be our 2009 fiscal year beginning September 28, 2008. We are currently in the process of evaluating the impact that SFAS 159 may have on our consolidated financial position, results of operations and cash flows.
In September 2006, the FASB issued SFAS No. 157, ‘‘Fair Value Measurements’’ (‘‘SFAS 157’’). SFAS 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. It also establishes a fair value hierarchy that prioritizes information used in developing assumptions when pricing an asset or liability. Like SFAS 159 above, SFAS 157 will be effective for fiscal years beginning after November 15, 2007, which will be our 2009 fiscal year beginning September 28, 2008. We are currently in the process of evaluating the impact that SFAS 157 may have on our consolidated financial position, results of operations and cash flows.
In June 2006, the FASB issued FASB Interpretation No. 48, ‘‘Accounting for Uncertainty in Income Taxes – An Interpretation of FASB Statement No. 109’’ (‘‘FIN 48’’). FIN 48 requires companies to determine whether it is more likely than not that a tax position will be sustained upon examination by the appropriate taxing authorities before any part of the benefit can be recorded in the financial statements. FIN 48 is effective for fiscal years beginning after December 15, 2006, which will be our 2008 fiscal year beginning September 30, 2007. We are currently in the process of assessing the impact that FIN 48 will have on our consolidated financial statements and currently do not expect that adoption of FIN 48 will have a material impact on our financial position, results of operation or cash flows.
44
Table of Contents![]()
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Commodity Price Risk
We enter into product supply contracts that are generally one-year agreements subject to annual renewal, and also purchase product on the open market. Our propane supply contracts typically provide for pricing based upon index formulas using the posted prices established at major supply points such as Mont Belvieu, Texas, or Conway, Kansas (plus transportation costs) at the time of delivery. In addition, to supplement our annual purchase requirements, we may utilize forward fixed price purchase contracts to acquire a portion of the propane that we resell to our customers, which allows us to manage our exposure to unfavorable changes in commodity prices and to assure adequate physical supply. The percentage of contract purchases, and the amount of supply contracted for under forward contracts at fixed prices, will vary from year to year based on market conditions. In certain instances, and when market conditions are favorable as was the case in the fuel oil market during the first half of fiscal 2007, we are able to purchase product under our supply arrangements at a discount to the market.
Product cost changes can occur rapidly over a short period of time and can impact profitability. We attempt to reduce price risk by pricing product on a short-term basis. The level of priced, physical product maintained in storage facilities and at our customer service centers for immediate sale to our customers will vary depending on several factors, including, but not limited to, price, availability of supply and demand given the time of year. Typically, our on hand priced position does not exceed more than four weeks of our supply needs and, during the peak heating season, typically not more than two weeks of supply is maintained in inventory. In the course of normal operations, we routinely enter into contracts such as forward priced physical contracts for the purchase or sale of propane and fuel oil that, under SFAS 133, qualify for and are designated as a normal purchase or normal sale contract. Such contracts are exempted from the fair value accounting requirements of SFAS 133 and are accounted for at the time product is purchased or sold under the related contract.
Under our hedging and risk management strategies, we enter into a combination of exchange-traded futures and option contracts, forward contracts and, in certain instances, over-the-counter options (collectively, ‘‘derivative instruments’’) to manage the price risk associated with priced, physical product and with future purchases of the commodities used in our operations, principally propane and fuel oil, as well as to ensure the availability of product during periods of high demand. Futures and forward contracts require that we sell or acquire propane or fuel oil at a fixed price for delivery at fixed future dates. An option contract allows, but does not require, its holder to buy or sell propane or fuel oil at a specified price during a specified time period. However, the writer of an option contract must fulfill the obligation of the option contract, should the holder choose to exercise the option. At expiration, the contracts are settled by the delivery of the product to the respective party or are settled by the payment of a net amount equal to the difference between the then current price and the fixed contract price. To the extent that we utilize derivative instruments to manage exposure to commodity price risk and commodity prices move adversely in relation to the contracts, we could suffer losses on those derivative instruments when settled. Conversely, if prices move favorably, we could realize gains.
As a result of various market factors during the first half of fiscal 2007, particularly commodity price volatility during the first four months of the fiscal year, we experienced additional margin opportunities due to favorable pricing under certain supply arrangements and from our hedging and risk management activities. We attribute approximately $14.7 million of the fiscal 2007 profitability to the favorable supply and market factors. However, supply and risk management transactions may not always result in increased product margins and there can be no assurance that these favorable market conditions will be present in the future in order to provide the additional margin opportunities realized during fiscal 2007.
45
Table of ContentsMarket Risk
We are subject to commodity price risk to the extent that propane or fuel oil market prices deviate from fixed contract settlement amounts. Futures traded with brokers on the NYMEX require daily cash settlements in margin accounts. Forward and option contracts are generally settled at the expiration of the contract term either by physical delivery or through a net settlement mechanism. Market risks associated with the trading of futures, options and forward contracts are monitored daily for compliance with our Hedging and Risk Management Policy which includes volume limits for open positions. Open inventory positions are reviewed and managed daily as to exposures to changing market prices.
Credit Risk
Futures and fuel oil options are guaranteed by the NYMEX and, as a result, have minimal credit risk. We are subject to credit risk with forward and option contracts to the extent the counterparties do not perform. We evaluate the financial condition of each counterparty with which we conduct business and establish credit limits to reduce exposure to credit risk of non-performance.
Interest Rate Risk
A portion of our long-term borrowings bear interest at a variable rate based upon either LIBOR or Wachovia National Bank’s prime rate, plus an applicable margin depending on the level of our total leverage. Therefore, we are subject to interest rate risk on the variable component of the interest rate. We manage our interest rate risk by entering into interest rate swap agreements. On March 31, 2005, we entered into a $125.0 million interest rate swap contract in conjunction with the Term Loan facility under the Revolving Credit Agreement. The interest rate swap is being accounted for under SFAS 133 and has been designated as a cash flow hedge. Changes in the fair value of the interest rate swap are recognized in other comprehensive (loss) income (‘‘OCI’’) until the hedged item is recognized in earnings. At September 29, 2007, the fair value of the interest rate swap was ($0.3) million representing an unrealized loss and was included within other liabilities.
Derivative Instruments and Hedging Activities
All of our derivative instruments are reported on the balance sheet, within other current assets or other current liabilities, at their fair values pursuant to SFAS 133. On the date that futures, forward and option contracts are entered into, we make a determination as to whether the derivative instrument qualifies for designation as a hedge. Changes in the fair value of derivative instruments are recorded each period in current period earnings or OCI, depending on whether a derivative instrument is designated as a hedge and, if so, the type of hedge. For derivative instruments designated as cash flow hedges, we formally assess, both at the hedge contract’s inception and on an ongoing basis, whether the hedge contract is highly effective in offsetting changes in cash flows of hedged items. Changes in the fair value of derivative instruments designated as cash flow hedges are reported in OCI to the extent effective and reclassified into cost of products sold during the same period in which the hedged item affects earnings. The mark-to-market gains or losses on ineffective portions of cash flow hedges used to hedge future purchases are immediately recognized in cost of products sold. Changes in the fair value of derivative instruments that are not designated as cash flow hedges, and that do not meet the normal purchase and normal sale exemption under SFAS 133, are recorded within cost of products sold as they occur.
At September 29, 2007, the fair value of derivative instruments described above resulted in derivative assets (unrealized gains) of $2.5 million included within prepaid expenses and other current assets and derivative liabilities (unrealized losses) of $0.5 million included within other current liabilities. Cost of products sold included unrealized (non-cash) losses in the amount of $7.6 million for the year ended September 29, 2007 compared to unrealized (non-cash) gains of $14.5 million for the year ended September 30, 2006, attributable to the change in fair value of derivative instruments not designated as cash flow hedges. As of September 29, 2007, unrealized gains on derivative instruments designated as cash flow hedges in the amount of $1.4 million were included in OCI and are expected to be recognized in earnings during the next 12 months as the hedged transactions occur.
46
Table of ContentsSensitivity Analysis
In an effort to estimate our exposure to unfavorable market price changes in propane or fuel oil related to our open positions under derivative instruments, we developed a model that incorporates the following data and assumptions:
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A. The actual fixed contract price of open positions as of September 29, 2007 for each of the future periods.
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B. The estimated future market prices for futures and forward contracts as of September 29, 2007 as derived from the NYMEX for traded propane or fuel oil futures for each of the future periods.
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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 indicates either future losses or a reduction in potential future gains of $5.8 million as of September 29, 2007. The above hypothetical change does not reflect the worst case scenario. Actual results may be significantly different depending on market conditions and the composition of the open position portfolio. The average posted price of propane on September 29, 2007 at Mont Belvieu, Texas (a major storage point) was $1.341 per gallon as compared to $0.9475 per gallon on September 30, 2006. The average posted price of fuel oil on September 29, 2007 at Linden, New Jersey was $2.2379 per gallon as compared to $1.685 per gallon on September 30, 2006. The average posted price of propane on November 20, 2007 at Mont Belvieu, Texas was $1.563 per gallon, representing a 16.6% increase since the end of fiscal 2007. The average posted price of fuel oil on November 20, 2007 at Linden, New Jersey was $2.6739 per gallon, representing a 19.5% increase since the end of fiscal 2007.
As of September 29, 2007, our open positions under derivative instruments reflected a net short position (sell contracts) aggregating $32.2 million.
47
Table of Contents![]()
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Our Consolidated Financial Statements and the Report of Independent Registered Public Accounting Firm thereon listed on the accompanying Index to Financial Statements (see page F-1) and the Supplemental Financial Information listed on the accompanying Index to Financial Statement Schedule (see page S-1) are included herein.
Selected Quarterly Financial Data
Due to the seasonality of the retail propane business, our first and second quarter revenues and earnings are consistently greater than third and fourth quarter results. The following presents our selected quarterly financial data for the last two fiscal years (unaudited; in thousands, except per unit amounts).
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First
Quarter![]()
Second
Quarter![]()
Third
Quarter![]()
Fourth
Quarter
(a)(g)![]()
Total Year
(a) Fiscal 2007![]()
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Revenues
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$ 397,908
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$ 555,111
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$ 271,454
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$ 215,090
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$ 1,439,563
Income (loss) before interest expense and provision for income taxes (b)
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63,062
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114,972
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7,261
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(20,699 )
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164,596
Income (loss) from continuing operations (b)
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53,084
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105,272
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(1,751 )
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(33,258 )
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123,347
Discontinued operations:
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Gain on disposal of discontinued operations (c)
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1,002
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—
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203
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682
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1,887
Income from discontinued operations (d)
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568
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588
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408
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489
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2,053
Net income (loss) (b)
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54,654
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105,860
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(1,140 )
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(32,087 )
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127,287
Net income (loss) from continuing operations per
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common unit – basic (e)
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1.65
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3.22
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(0.05 )
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(1.02 )
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3.79
Net income (loss) per common unit – basic (e)
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1.70
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3.24
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(0.03 )
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(0.99 )
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3.91
Net income (loss) per common unit – diluted (e)
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1.69
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3.22
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(0.03 )
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(0.99 )
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3.89
Cash (used in) provided by
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Operating activities
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(5,893 )
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87,120
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46,788
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17,942
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145,957
Investing activities
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(6,663 )
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(2,048 )
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(5,981 )
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(4,997 )
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(19,689 ) Financing activities
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(21,637 )
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(22,464 )
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(22,872 )
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(23,280 )
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(90,253 ) EBITDA (f)
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$ 71,768
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$ 123,130
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$ 15,303
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$ (12,423 )
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$ 197,778
Retail gallons sold
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Propane
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121,764
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166,796
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80,042
![]()
![]()
![]()
![]()
63,924
![]()
![]()
![]()
![]()
432,526
Fuel oil and refined fuels
![]()
![]()
![]()
28,498
![]()
![]()
![]()
![]()
43,997
![]()
![]()
![]()
![]()
19,144
![]()
![]()
![]()
![]()
12,867
![]()
![]()
![]()
![]()
104,506
Fiscal 2006
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
Revenues
![]()
![]()
$ 486,160
![]()
![]()
![]()
$ 589,788
![]()
![]()
![]()
$ 303,048
![]()
![]()
![]()
$ 278,134
![]()
![]()
![]()
$ 1,657,130
Income (loss) before interest expense and provision for income taxes (b)
![]()
![]()
![]()
48,109
![]()
![]()
![]()
![]()
94,345
![]()
![]()
![]()
![]()
(1,097 )
![]()
![]()
![]()
(11,619 )
![]()
![]()
![]()
129,738
Income (loss) from continuing operations (b)
![]()
![]()
![]()
37,392
![]()
![]()
![]()
![]()
83,323
![]()
![]()
![]()
![]()
(10,904 )
![]()
![]()
![]()
(21,517 )
![]()
![]()
![]()
88,294
Discontinued operations:
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
Income from discontinued operations (d)
![]()
![]()
![]()
823
![]()
![]()
![]()
![]()
706
![]()
![]()
![]()
![]()
431
![]()
![]()
![]()
![]()
486
![]()
![]()
![]()
![]()
2,446
Net income (loss) (b)
![]()
![]()
![]()
38,215
![]()
![]()
![]()
![]()
84,029
![]()
![]()
![]()
![]()
(10,473 )
![]()
![]()
![]()
(21,031 )
![]()
![]()
![]()
90,740
Net income (loss) from continuing operations per
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
common unit – basic (e)
![]()
![]()
![]()
1.12
![]()
![]()
![]()
![]()
2.42
![]()
![]()
![]()
![]()
(0.34 )
![]()
![]()
![]()
(0.68 )
![]()
![]()
![]()
2.76
Net income (loss) per common unit – basic (e)
![]()
![]()
![]()
1.15
![]()
![]()
![]()
![]()
2.44
![]()
![]()
![]()
![]()
(0.33 )
![]()
![]()
![]()
(0.66 )
![]()
![]()
![]()
2.84
Net income (loss) per common unit – diluted (e)
![]()
![]()
![]()
1.14
![]()
![]()
![]()
![]()
2.43
![]()
![]()
![]()
![]()
(0.33 )
![]()
![]()
![]()
(0.66 )
![]()
![]()
![]()
2.83
Cash (used in) provided by
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
Operating activities
![]()
![]()
![]()
(8,932 )
![]()
![]()
![]()
63,768
![]()
![]()
![]()
![]()
66,048
![]()
![]()
![]()
![]()
49,437
![]()
![]()
![]()
![]()
170,321
Investing activities
![]()
![]()
![]()
(5,938 )
![]()
![]()
![]()
(3,303 )
![]()
![]()
![]()
(3,184 )
![]()
![]()
![]()
(6,667 )
![]()
![]()
![]()
(19,092 ) Financing activities
![]()
![]()
![]()
17,088
![]()
![]()
![]()
![]()
(60,411 )
![]()
![]()
![]()
(41,671 )
![]()
![]()
![]()
(20,075 )
![]()
![]()
![]()
(105,069 ) EBITDA (f)
![]()
![]()
$ 57,143
![]()
![]()
![]()
$ 103,949
![]()
![]()
![]()
$ 7,090
![]()
![]()
![]()
$ (2,847 )
![]()
![]()
$ 165,335
Retail gallons sold
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
Propane
![]()
![]()
![]()
133,811
![]()
![]()
![]()
![]()
168,847
![]()
![]()
![]()
![]()
88,661
![]()
![]()
![]()
![]()
75,460
![]()
![]()
![]()
![]()
466,779
Fuel oil and refined fuels
![]()
![]()
![]()
43,816
![]()
![]()
![]()
![]()
54,699
![]()
![]()
![]()
![]()
26,563
![]()
![]()
![]()
![]()
20,538
![]()
![]()
![]()
![]()
145,616
![]()
![]()
![]()
![]()
(a) Fiscal 2006 includes 53 weeks of operations compared to 52 weeks in fiscal 2007. The fourth quarter of fiscal 2006 includes 14 weeks of operations compared to 13 weeks in the fourth quarter of fiscal 2007.
48
Table of Contents (b) These amounts include gains from the disposal of property, plant and equipment of $2.8 million for fiscal 2007 and $1.0 million for fiscal 2006. (c) Gain on disposal of discontinued operations reflects (i) a $1.0 million gain on the non-cash exchange of nine non-strategic customer service centers for three customer service centers of another company in Alaska during the first quarter of fiscal 2007; (ii) a $0.2 million gain on the sale of one customer service center for net cash proceeds of $0.3 million during the third quarter of fiscal 2007; and (iii) a $0.7 million gain on the sale of two customer service centers for net cash proceeds of $1.0 million during the fourth quarter of fiscal 2007. These gains were accounted for within discontinued operations pursuant to SFAS 144. (d) On October 2, 2007, we completed the Tirzah Sale. As a result of this sale, a gain of approximately $40.0 million will be reported as a gain from the disposal of discontinued operations in our results for the first quarter of fiscal 2008. The results of operations from the Tirzah facilities have been reported within discontinued operations. Because the transaction closed subsequent to the end of fiscal 2007, our cash on hand at September 29, 2007 does not include the net proceeds of approximately $54.0 million. (e) Computations of earnings per Common Unit for the year ended September 29, 2007 were performed in accordance with SFAS No. 128 ‘‘Earnings per Share’’ (‘‘SFAS 128’’) by dividing net income by the weighted average number of outstanding Common Units. For fiscal 2006, earnings per Common Unit were performed in accordance with Emerging Issues Task Force consensus 03-6 ‘‘Participating Securities and the Two-Class Method Under FAS 128’’ (‘‘EITF 03-6’’), when applicable. EITF 03-6 requires, among other things, the use of the two-class method of computing earnings per unit when participating securities exist. The two-class method is an earnings allocation formula that computes earnings per unit for each class of Common Unit and participating security according to distributions declared and participating rights in undistributed earnings, as if all of the earnings were distributed to the limited partners and the General Partner (inclusive of the previously outstanding IDRs of the General Partner which were considered participating securities for purposes of the two-class method). Net income was allocated to the Common Unitholders and the General Partner in accordance with their respective partnership ownership interests, after giving effect to any priority income allocations for IDRs of the General Partner. As a result of the GP Exchange Transaction on October 19, 2006, the two-class method of computing income per Common Unit under EITF 03-6 is no longer applicable.The requirements of EITF 03-6 do not apply to the computation of earnings per Common Unit in periods in which a net loss is reported and therefore did not have any impact on the third and fourth quarters of fiscal 2006. Net income and income from continuing operations per Common Unit presented in this table for the first and second quarters of fiscal 2006 and for the year ended September 30, 2006 reflect the impact of the application of EITF 03-6. Basic net income (loss) per Common Unit computed under SFAS 128 is computed by dividing net income (loss), after deducting our General Partner’s interest, by the weighted average number of outstanding Common Units. Diluted net income per Common Unit is computed by dividing net income (loss) by the weighted average number of outstanding Common Units and unvested restricted units granted under our 2000 Restricted Unit Plan. For purposes of the computation of income per Common Unit for the year ended September 30, 2007, earnings that would have been allocated to the General Partner for the period prior to the GP Exchange Transaction were not significant.
(f) EBITDA represents net income before deducting interest expense, income taxes, depreciation and amortization. Our management uses EBITDA as a measure of liquidity and we are including it because we believe that it provides our investors and industry analysts with additional information to evaluate our ability to meet our debt service obligations and to pay our quarterly distributions to holders of our Common Units. In addition, certain of our incentive compensation plans covering executives and other employees utilize EBITDA as the performance target. We use this non-GAAP financial measure in order to assist industry analysts and investors in assessing our liquidity on a year-over-year and quarter-to-quarter basis. Moreover, our revolving credit agreement requires us to use EBITDA as a component in calculating our leverage and interest49
Table of Contents coverage ratios. EBITDA is not a recognized term under GAAP and should not be considered as an alternative to net income or net cash provided by operating activities determined in accordance with GAAP. Because EBITDA as determined by us excludes some, but not all, items that affect net income, it may not be comparable to EBITDA or similarly titled measures used by other companies. The following table sets forth (i) our calculations of EBITDA and (ii) a reconciliation of EBITDA, as so calculated, to our net cash provided by operating activities (amounts in thousands):
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
Fiscal 2007
![]()
First
Quarter![]()
Second
Quarter![]()
Third
Quarter![]()
Fourth
Quarter![]()
Total
Year Net income (loss)![]()
![]()
$ 54,654
![]()
![]()
![]()
$ 105,860
![]()
![]()
![]()
$ (1,140 )
![]()
![]()
$ (32,087 )
![]()
![]()
$ 127,287
Add:
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
Provision for income taxes
![]()
![]()
![]()
762
![]()
![]()
![]()
![]()
378
![]()
![]()
![]()
![]()
389
![]()
![]()
![]()
![]()
4,124
![]()
![]()
![]()
![]()
5,653
Interest expense, net
![]()
![]()
![]()
9,216
![]()
![]()
![]()
![]()
9,322
![]()
![]()
![]()
![]()
8,623
![]()
![]()
![]()
![]()
8,435
![]()
![]()
![]()
![]()
35,596
Depreciation and amortization:
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
Continuing operations
![]()
![]()
![]()
7,010
![]()
![]()
![]()
![]()
7,446
![]()
![]()
![]()
![]()
7,306
![]()
![]()
![]()
![]()
7,028
![]()
![]()
![]()
![]()
28,790
Discontinued operations
![]()
![]()
![]()
126
![]()
![]()
![]()
![]()
124
![]()
![]()
![]()
![]()
125
![]()
![]()
![]()
![]()
77
![]()
![]()
![]()
![]()
452
EBITDA
![]()
![]()
![]()
71,768
![]()
![]()
![]()
![]()
123,130
![]()
![]()
![]()
![]()
15,303
![]()
![]()
![]()
![]()
(12,423 )
![]()
![]()
![]()
197,778
Add (subtract):
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
Provision for income taxes – current
![]()
![]()
![]()
(762 )
![]()
![]()
![]()
(378 )
![]()
![]()
![]()
(389 )
![]()
![]()
![]()
(324 )
![]()
![]()
![]()
(1,853 ) Interest expense, net
![]()
![]()
![]()
(9,216 )
![]()
![]()
![]()
(9,322 )
![]()
![]()
![]()
(8,623 )
![]()
![]()
![]()
(8,435 )
![]()
![]()
![]()
(35,596 ) Compensation cost recognized under Restricted Unit Plan
![]()
![]()
![]()
1,297
![]()
![]()
![]()
![]()
(137 )
![]()
![]()
![]()
949
![]()
![]()
![]()
![]()
905
![]()
![]()
![]()
![]()
3,014
Gain on disposal of property, plant and equipment, net
![]()
![]()
![]()
(247 )
![]()
![]()
![]()
(1,815 )
![]()
![]()
![]()
(339 )
![]()
![]()
![]()
(381 )
![]()
![]()
![]()
(2,782 ) Gain on disposal of discontinued operations
![]()
![]()
![]()
(1,002 )
![]()
![]()
![]()
—
![]()
![]()
![]()
![]()
(203 )
![]()
![]()
![]()
(682 )
![]()
![]()
![]()
(1,887 ) Pension settlement charge
![]()
![]()
![]()
—
![]()
![]()
![]()
![]()
—
![]()
![]()
![]()
![]()
—
![]()
![]()
![]()
![]()
3,269
![]()
![]()
![]()
![]()
3,269
Changes in working capital and other assets and liabilities
![]()
![]()
![]()
(67,731 )
![]()
![]()
![]()
(24,358 )
![]()
![]()
![]()
40,090
![]()
![]()
![]()
![]()
36,013
![]()
![]()
![]()
![]()
(15,986 ) Net cash provided by operating activities
![]()
![]()
$ (5,893 )
![]()
![]()
$ 87,120
![]()
![]()
![]()
$ 46,788
![]()
![]()
![]()
$ 17,942
![]()
![]()
![]()
$ 145,957
![]()
50
Table of Contents
(g) The fourth quarter of fiscal 2007 includes a $3.8 million adjustment related to the provision for income taxes – deferred taxes related to the utilization of net operating losses in the first quarter of fiscal 2007.![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
Fiscal 2006
![]()
First
Quarter![]()
Second
Quarter![]()
Third
Quarter![]()
Fourth
Quarter![]()
Total
Year Net income (loss)![]()
![]()
$ 38,215
![]()
![]()
![]()
$ 84,029
![]()
![]()
![]()
$ (10,473 )
![]()
![]()
$ (21,031 )
![]()
![]()
$ 90,740
Add:
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
Provision for income taxes
![]()
![]()
![]()
150
![]()
![]()
![]()
![]()
83
![]()
![]()
![]()
![]()
121
![]()
![]()
![]()
![]()
410
![]()
![]()
![]()
![]()
764
Interest expense, net
![]()
![]()
![]()
10,567
![]()
![]()
![]()
![]()
10,939
![]()
![]()
![]()
![]()
9,686
![]()
![]()
![]()
![]()
9,488
![]()
![]()
![]()
![]()
40,680
Depreciation and amortization:
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
Continuing operations
![]()
![]()
![]()
8,089
![]()
![]()
![]()
![]()
8,777
![]()
![]()
![]()
![]()
7,634
![]()
![]()
![]()
![]()
8,153
![]()
![]()
![]()
![]()
32,653
Discontinued operations
![]()
![]()
![]()
122
![]()
![]()
![]()
![]()
121
![]()
![]()
![]()
![]()
122
![]()
![]()
![]()
![]()
133
![]()
![]()
![]()
![]()
498
EBITDA
![]()
![]()
![]()
57,143
![]()
![]()
![]()
![]()
103,949
![]()
![]()
![]()
![]()
7,090
![]()
![]()
![]()
![]()
(2,847 )
![]()
![]()
![]()
165,335
Add (subtract):
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
![]()
Provision for income taxes
![]()
![]()
![]()
(150 )
![]()
![]()
![]()
(83 )
![]()
![]()
![]()
(121 )
![]()
![]()
![]()
(410 )
![]()
![]()
![]()
(764 ) Interest expense, net
![]()
![]()
![]()
(10,567 )
![]()
![]()
![]()
(10,939 )
![]()
![]()
![]()
(9,686 )
![]()
![]()
![]()
(9,488 )
![]()
![]()
![]()
(40,680 ) Compensation cost recognized under Restricted Unit Plan
![]()
![]()
![]()
615
![]()
![]()
![]()
![]()
561
![]()
![]()
![]()
![]()
472
![]()
![]()
![]()
![]()
573
![]()
![]()
![]()
![]()
2,221
(Gain) loss on disposal of property, plant and equipment, net
![]()
![]()
![]()
(44 )
![]()
![]()
![]()
(577 )
![]()
![]()
![]()
(568 )
![]()
![]()
![]()
189
![]()
![]()
![]()
![]()
(1,000 ) Pension settlement charge
![]()
![]()
![]()
—
![]()
![]()
![]()
![]()
—
![]()
![]()
![]()
![]()
—
![]()
![]()
![]()
![]()
4,437
![]()
![]()
![]()
![]()
4,437
Changes in working capital and other assets and liabilities
![]()
![]()
![]()
(55,929 )
![]()
![]()
![]()
(29,143 )
![]()
![]()
![]()
68,861
![]()
![]()
![]()
![]()
56,983
![]()
![]()
![]()
![]()
40,772
Net cash provided by operating activities
![]()
![]()
$ (8,932 )
![]()
![]()
$ 63,768
![]()
![]()
![]()
$ 66,048
![]()
![]()
![]()
$ 49,437
![]()
![]()
![]()
$ 170,321
![]()
51
Table of Contents![]()
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
![]()
ITEM 9A. CONTROLS AND PROCEDURES
DISCLOSURE CONTROLS AND PROCEDURES. The Partnership maintains disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (the ‘‘Exchange Act’’)) that are designed to provide reasonable assurance that information required to be disclosed in the Partnership’s filings under the Exchange Act is recorded, processed, summarized and reported within the periods specified in the rules and forms of the SEC and that such information is accumulated and communicated to the Partnership’s management, including its principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.
Before filing this Annual Report, the Partnership completed an evaluation under the supervision and with the participation of the Partnership’s management, including the Partnership’s principal executive officer and principal financial officer, of the effectiveness of the design and operation of the Partnership’s disclosure controls and procedures as of September 29, 2007. Based on this evaluation, the Partnership’s principal executive officer and principal financial officer concluded that the Partnership’s disclosure controls and procedures were effective at the reasonable assurance level as of September 29, 2007.
CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING. There have not been any changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) during the quarter ended September 29, 2007, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. Management’s Report on Internal Control over Financial Reporting is included below.
In the ordinary course of business, we review our system of internal control over financial reporting and make changes to our systems and processes to improve controls and increase efficiency, while ensuring that we maintain an effective internal control environment. Changes may include such activities as implementing new, more efficient systems and automating manual processes.
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING. Management of the Partnership is responsible for establishing and maintaining adequate internal control over financial reporting. The Partnership’s internal control over financial reporting is designed to provide reasonable assurance as to the reliability of the Partnership’s financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
The Partnership’s management has assessed the effectiveness of the Partnership’s internal control over financial reporting as of September 29, 2007. In making this assessment, the Partnership used the criteria established by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in ‘‘Internal Control-Integrated Framework.’’ These criteria are in the areas of control environment, risk assessment, control activities, information and communication, and monitoring. The Partnership’s assessment included documenting, evaluating and testing the design and operating effectiveness of its internal control over financial reporting.
Based on the Partnership’s assessment, as described above, management has concluded that, as of September 29, 2007, the Partnership’s internal control over financial reporting was effective.
52
Table of ContentsManagement’s assessment of the effectiveness of the Partnership’s internal control over financial reporting as of September 29, 2007 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears in the ‘‘Report of Independent Registered Public Accounting Firm’’ on page F-2 of this Annual Report.
![]()
ITEM 9B. OTHER INFORMATION
None.
53
Table of ContentsPART III
![]()
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Partnership Management
Our Partnership Agreement provides that all management powers over our business and affairs are exclusively vested in our Board of Supervisors and, subject to the direction of the Board of Supervisors, our officers. No Unitholder has any management power over our business and affairs or actual or apparent authority to enter into contracts on behalf of or otherwise to bind us. There are currently seven Supervisors, who serve on the Board of Supervisors pursuant to the terms of the Partnership Agreement. Prior to adoption of the current Partnership Agreement on October 19, 2006, following approval thereof by the Common Unitholders, Common Unitholders elected three Supervisors to serve a three-year term and the General Partner appointed two Supervisors. Under the current Partnership Agreement, all Supervisors are elected by the Common Unitholders for three-year terms and the two Supervisors appointed by the General Partner, Messrs. Alexander and Dunn, will continue to serve until the next Tri-Annual Meeting of the Unitholders (currently scheduled for fiscal 2009), at which meeting all Supervisors will be elected by the Common Unitholders.
On January 31, 2007, acting on authority granted to it under the Partnership Agreement, the Board of Supervisors increased its size from five to seven Supervisors and appointed John D. Collins and Jane Swift to fill the vacancies thereby created, effective April 25, 2007. Mr. Collins and Ms. Swift will continue to serve on the Board of Supervisors until the next Tri-Annual Meeting of the Unitholders, at which time they will be subject to re-election by the Common Unitholders.
Five Supervisors, who are not officers or employees of the Partnership or its subsidiaries, serve on the Audit Committee with authority to review, at the request of the Board of Supervisors, specific matters as to which the Board of Supervisors believes there may be a conflict of interest in order to determine if the resolution or course of action in respect of such conflict proposed by the Board of Supervisors is fair and reasonable to us. Under the Partnership Agreement, any matter that receives the ‘‘Special Approval’’ of the Audit Committee (i.e., approval by a majority of the members of the Audit Committee) is conclusively deemed to be fair and reasonable to us, is deemed approved by all of our partners and shall not constitute a breach of the Partnership Agreement or any duty stated or implied by law or equity as long as the material facts known to the party having the potential conflict of interest regarding that matter were disclosed to the Audit Committee at the time it gave Special Approval. The Audit Committee also assists the Board of Supervisors in fulfilling its oversight responsibilities relating to (a) integrity of the Partnership’s financial statements and internal controls over financial reporting; (b) the Partnership’s compliance with applicable laws, regulations and its code of conduct; (c) independence and qualifications of the independent registered public accounting firm; and (d) performance of the internal audit function and the independent registered public accounting firm.
Mr. Collins has advised the Board of Supervisors that he currently serves on the audit committees of four public companies, including the Partnership. In accordance with the rules of the NYSE, the Board of Supervisors has determined that Mr. Collins’ simultaneous service on four audit committees would not impair his ability to effectively serve on the Audit Committee of the Partnership’s Board of Supervisors.
The Board of Supervisors has determined that all five members of the Audit Committee, Harold R. Logan, Jr., John Hoyt Stookey, Dudley C. Mecum, John D. Collins and Jane Swift are audit committee financial experts and are independent within the meaning of the NYSE corporate governance listing standards and in accordance with Item 407 of Regulation S-K as of the date of this Annual Report. Mr. Logan, Chairman of the Audit Committee, presides at the regularly scheduled executive sessions of the non-management Supervisors, all of whom are independent, held as part of the meetings of the Audit Committee. On October 31, 2007, the Audit Committee approved the nomination to appoint Mr. Collins as Chairman of the Audit Committee, effective January 24, 2008. Investors and other parties interested in communicating directly with the non-management supervisors
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Table of Contentsas a group may do so by writing to the Non-Management Members of the Board of Supervisors, c/o Company Secretary, Suburban Propane Partners, L.P., P.O. Box 206, Whippany, New Jersey 07981-0206.
Board of Supervisors and Executive Officers of the Partnership
The following table sets forth certain information with respect to the members of the Board of Supervisors and our executive officers as of November 20, 2007. Officers are appointed by the Board of Supervisors for one-year terms and Supervisors are elected by the Unitholders for three-year terms.
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Name
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Age
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Position With the Partnership Mark A. Alexander
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49
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Chief Executive Officer; Member of the Board of Supervisors Michael J. Dunn, Jr.
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58
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President; Member of the Board of Supervisors Michael A. Stivala
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38
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Chief Financial Officer and Chief Accounting Officer A. Davin D’Ambrosio
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43
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Vice President and Treasurer Paul Abel
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Vice President, General Counsel and Secretary William E. Anderson
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51
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Northeast Area Vice President Mark Anton, II
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50
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Vice President – Business Development Steven C. Boyd
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43
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Southeast and Western Area Vice President Douglas T. Brinkworth
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46
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Vice President – Supply Michael M. Keating
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Vice President – Human Resources and Administration Mark Wienberg
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45
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Vice President – Operational Planning and Analysis Michael Kuglin
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37
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Controller Harold R. Logan, Jr.
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63
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Member of the Board of Supervisors (Chairman and Chairman of the Audit Committee) John Hoyt Stookey
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77
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Member of the Board of Supervisors (Chairman of the Compensation Committee) Dudley C. Mecum
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72
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Member of the Board of Supervisors John D. Collins
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69
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Member of the Board of Supervisors Jane Swift
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42
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Member of the Board of Supervisors
Mr. Alexander has served as Chief Executive Officer and as a Supervisor since March 1996, and as President from October 1996 until May 2005. He was Executive Vice Chairman from March 1996 through October 1996. From 1989 until joining the Partnership, Mr. Alexander was an officer of Hanson Industries (the United States management division of Hanson plc, a global diversified industrial conglomerate), most recently Senior Vice President – Corporate Development. Mr. Alexander is the sole member of the General Partner. Mr. Alexander is a Director of Kaydon Corporation.
Mr. Dunn became President in May 2005. From June 1998 until that date he was Senior Vice President, becoming Senior Vice President – Corporate Development in November 2002. Mr. Dunn has served as a Supervisor since July 1998. He was Vice President – Procurement and Logistics from March 1997 until June 1998. Before joining the Partnership, Mr. Dunn was Vice President of Commodity Trading for the investment banking firm of Goldman Sachs & Company (‘‘Goldman Sachs’’).
Mr. Stivala has served as Chief Financial Officer and Chief Accounting Officer since October 2007. Prior to that he was Controller and Chief Accounting Officer since May 2005 and Controller since December 2001. Before joining the Partnership, he held several positions with PricewaterhouseCoopers LLP, an international accounting firm, most recently as Senior Manager in the Assurance practice. Mr. Stivala is a Certified Public Accountant and a member of the American Institute of Certified Public Accountants.
Mr. D’Ambrosio became Treasurer in November 2002 and was additionally made a Vice President in October 2007. He served as Assistant Treasurer from October 2000 to November 2002
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Table of Contentsand as Director of Treasury Services from January 1998 to October 2000. Mr. D’Ambrosio joined the Partnership in May 1996 after ten years in the commercial banking industry.
Mr. Abel has served as General Counsel and Secretary since June 2006 and was additionally made a Vice President in October 2007. From May 2005 until June 2006, Mr. Abel was Assistant General Counsel of Velocita Wireless, L.P., the owner and operator of a nationwide wireless data network. From 1998 until May 2005, Mr. Abel was Vice President, Secretary and General Counsel of AXS-One Inc. (formerly known as Computron Software, Inc.), an international business software company.
Mr. Anderson has served as Northeast Area Vice President since March 2007. He joined the Partnership in December 2003 as a Region General Manager upon the Partnership’s acquisition of Agway Energy, where he had also served as Region General Manager since before 2002.
Mr. Anton has served as Vice President, Business Development since he joined the Partnership in 1999. Prior to joining the Partnership, Mr. Anton worked as an Area Manager for another large multi-state propane marketer and was a Vice President at several large investment banking organizations.
Mr. Boyd has served as Southeast and Western Area Vice President since March 2007. Prior to that he was Managing Director – Area Operations since November 2003 and Regional Manager – Northern California since May 1997. Mr. Boyd held various managerial positions with predecessors of the Partnership from 1986 through 1996.
Mr. Brinkworth became Vice President – Supply in May 2005. Mr. Brinkworth joined the Partnership in April 1997 after a nine year career with Goldman Sachs and, since joining the Partnership, has served in various positions in the supply area, most recently as Managing Director.
Mr. Keating has served as Vice President – Human Resources and Administration since July 1996. He previously held senior human resource positions at Hanson Industries and Quantum Chemical Corporation (‘‘Quantum’’), a predecessor of the Partnership.
Mr. Wienberg has served as Vice President – Operational Planning and Analysis since October 2007. Prior to that he served as Managing Director, Financial Planning and Analysis from October 2003 to October 2007 and as Director, Financial Planning and Analysis from July 2001 to October 2003. Prior to joining the Partnership, Mr. Wienberg was Assistant Vice President – Finance of International Home Foods Corp., a consumer products manufacturer.
Mr. Kuglin became Controller in October 2007. For the eight years prior to joining the Partnership he held several financial and managerial positions with Alcatel-Lucent, a global communications solutions provider. Prior to Alcatel-Lucent, Mr. Kuglin held several positions with the international accounting firm PricewaterhouseCoopers LLP, most recently Manager in the Assurance practice. Mr. Kuglin is a Certified Public Accountant and a member of the American Institute of Certified Public Accountants.
Mr. Logan has served as a Supervisor since March 1996 and was elected as Chairman of the Board of Supervisors in January 2007. From 2003 to September 2006, Mr. Logan was a Director and Chairman of the Finance Committee of the Board of Directors of TransMontaigne Inc., which provided logistical services (i.e. pipeline, terminaling and marketing) to producers and end-users of refined petroleum products. From 1995 to 2002, Mr. Logan was Executive Vice President/Finance, Treasurer and a Director of TransMontaigne Inc. From 1987 to 1995, Mr. Logan served as Senior Vice President of Finance and a Director of Associated Natural Gas Corporation, an independent gatherer and marketer of natural gas, natural gas liquids and crude oil. Mr. Logan is also a Director of Graphic Packaging, Inc. and Hart Energy Publishing LLP.
Mr. Stookey has served as a Supervisor since March 1996. He was Chairman of the Board of Supervisors from March 1996 through January 2007. From 1986 until September 1993, he was the Chairman, President and Chief Executive Officer of Quantum. He served as non-executive Chairman and a Director of Quantum from its acquisition by Hanson plc in September 1993 until October 1995. Mr. Stookey is a non-executive Chairman of Per Scholas Inc. (a non-profit organization dedicated to using technology to improve the lives of residents of the South Bronx).
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Table of ContentsMr. Mecum has served as a Supervisor since June 1996. He has been a managing director of Capricorn Holdings, LLC (a sponsor of and investor in leveraged buyouts) since June 1997. Mr. Mecum was a partner of G.L. Ohrstrom & Co. (a sponsor of and investor in leveraged buyouts) from 1989 to June 1996.
Mr. Collins has served as a Supervisor since April 2007. He served with KPMG, LLP, an international accounting firm, from 1962 until 2000, most recently as senior audit partner of its New York office. He has served as a United States representative on the International Auditing Procedures Committee, a committee of international accountants responsible for establishing international auditing standards. Mr. Collins is a Director of Montpelier Re, Mrs. Fields Famous Brands, LLC and Excelsior Funds, and serves as a Trustee of LeMoyne College.
Ms. Swift has served as a Supervisor since April 2007. She is the founder of WNP Consulting, LLC, providing expert advice and guidance to early stage education companies. From 2003 – 2006 she was a General Partner at Arcadia Partners, a venture capital firm focused on the education industry. She currently serves on the boards of Animated Speech Company, Sally Ride Science Inc. and WellCare Health Plans, and several not-for-profit boards, including The Republican Majority for Choice and Landmark Volunteers, Inc. Prior to joining Arcadia, Ms. Swift served for 15 years in Massachusetts state government, becoming Massachusetts’ first woman governor in 2001.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act requires our Supervisors, executive officers and holders of ten percent or more of our Common Units to file initial reports of ownership and reports of changes in ownership of our Common Units with the SEC. Supervisors, executive officers and ten percent Unitholders are required to furnish the Partnership with copies of all Section 16(a) forms that they file. Based on a review of these filings, we believe that all such filings were timely made during fiscal 2007.
Codes of Ethics and of Business Conduct
We have adopted a Code of Ethics that applies to our principal executive officer, principal financial officer and principal accounting officer, and a Code of Business Conduct that applies to all of our employees, officers and Supervisors. Copies of our Code of Ethics and our Code of Business Conduct are available without charge from our website at www.suburbanpropane.com or upon written request directed to: Suburban Propane Partners, L.P., Investor Relations, P.O. Box 206, Whippany, New Jersey 07981-0206. Any amendments to, or waivers from, provisions of our Code of Ethics or our Code of Business Conduct that apply to our principal executive officer, principal financial officer and principal accounting officer will be posted on our website.
Corporate Governance Guidelines
We have adopted Corporate Governance Guidelines and Policies in accordance with the NYSE corporate governance listing standards in effect as of the date of this Annual Report. Copies of our Corporate Governance Guidelines are available without charge from our website at www.suburbanpropane.com or upon written request directed to: Suburban Propane Partners, L.P., Investor Relations, P.O. Box 206, Whippany, New Jersey 07981-0206.
Audit Committee Charter
We have adopted a written Audit Committee Charter in accordance with the NYSE corporate governance listing standards in effect as of the date of this Annual Report. The Audit Committee Charter is reviewed periodically to ensure that it meets all applicable legal and NYSE listing requirements. Copies of our Audit Committee Charter are available without charge from our website at www.suburbanpropane.com or upon written request directed to: Suburban Propane Partners, L.P., Investor Relations, P.O. Box 206, Whippany, New Jersey 07981-0206.
Compensation Committee Charter
Five Supervisors, who are not officers or employees of the Partnership or its subsidiaries, serve on the Compensation Committee. We have adopted a Compensation Committee Charter in accordance
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Table of Contentswith the NYSE corporate governance listing standards in effect as of the date of this Annual Report. Copies of our Compensation Committee Charter are available without charge from our website at www.suburbanpropane.com or upon written request directed to: Suburban Propane Partners, L.P., Investor Relations, P.O. Box 206, Whippany, New Jersey 07981-0206.
NYSE Annual CEO Certification
The NYSE requires the Chief Executive Officer of each listed company to submit a certification indicating that the company is not in violation of the Corporate Governance listing standards of the NYSE on an annual basis. Mr. Alexander submitted his Annual CEO Certification for 2007 to the NYSE without qualification.
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ITEM 11. EXECUTIVE COMPENSATION
COMPENSATION DISCUSSION AND ANALYSIS
This Compensation Discussion and Analysis provides a review of our executive compensation philosophy, policies and practices with respect to the following executive officers of the Partnership (the ‘‘named executive officers’’): the Chief Executive Officer, President, the Chief Financial Officer, the other two most highly compensated executive officers and one individual, Mr. Jolly, for whom disclosure would have been required but for the fact that he no longer served as an executive officer at the conclusion of fiscal 2007.
Executive Compensation Philosophy and Components
The objectives of our executive compensation program are as follows:
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• The attraction and retention of talented executives who have the skills and experience required to achieve our goals; and
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• The alignment of the short-term and long-term interests of our executive officers with the short-term and long-term interests of our Unitholders.
We accomplish these objectives by providing our executives with compensation packages that combine various components that are specifically linked to either short-term or long-term performance measures. Therefore, our executive compensation packages are designed to achieve our overall goal of sustainable, profitable growth by rewarding our executive officers for behaviors that facilitate our achieving this goal.
The principal components of the compensation we provide to our named executive officers are as follows:
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• Base salary;
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• Cash incentives paid under an annual bonus plan;
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• Long-term Incentive Plan grants; and
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• Discretionary grants of restricted units under the 2000 Restricted Unit Plan.
We align the short-term and long-term interests of our executive officers with the short-term and long-term interests of our Unitholders by:
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• Providing our executive officers with an annual incentive target that encourages them to achieve or exceed targeted financial results and operating performance for the fiscal year;
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• Providing a long-term incentive plan that encourages our executives to implement activities and practices conducive to sustainable, profitable growth because it permits them to share in benefits generated in the future; and
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• Providing a restricted unit plan that is utilized to retain the services of the participating executive officers over a five-year period while simultaneously encouraging behaviors conducive to the long-term appreciation of our Common Units.
Establishing Executive Compensation
The Compensation Committee (the ‘‘Committee’’) is responsible for overseeing our executive compensation program. In accordance with its charter, available on our website at www.suburbanpropane.com, the Committee ensures that the compensation packages provided to our executive officers are designed in accordance with our compensation philosophy. The Committee reviews and approves the compensation packages of all managing directors, vice presidents and the named executive officers.
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Table of ContentsAnnually, the Vice President of Human Resources prepares a comprehensive analysis of each executive officer’s past and current compensation to assist the Committee in the assessment and determination of executive compensation packages for the subsequent fiscal year. The Committee considers a number of factors in establishing the compensation packages for each executive officer, including, but not limited to, tenure, scope of responsibility and individual performance. The relative importance assigned to each of these factors by the Committee may differ from executive to executive. The performance of each of our executive officers is continually assessed by the Committee and by our highest-ranking executive officers and also factors into the decision-making process, particularly in relation to promotions and increases in base compensation. In addition, as part of the Committee’s annual review of each executive officer’s fiscal 2007 total compensation package, the Committee was provided with benchmarking data for a relevant peer group of companies for comparison purposes. The benchmarking data is just one of a number of factors considered by the Committee, but is not necessarily the most persuasive factor.
The benchmarking data was derived from the Mercer Human Resource Consulting, Inc. (‘‘Mercer’’) Benchmark Database containing information obtained from surveys of over 2,500 organizations and 167 positions which may include similarly-sized national propane marketers. The Committee does not base its benchmarking solely on a peer group of other propane marketers. The use of the Mercer database provides a broad base of compensation benchmarking information for companies of a similar size to Suburban. The peer group used for the Suburban positions consisted of organizations included in the Mercer database that report annual revenues of between $1.0 billion and $2.5 billion per year. The Committee used the median total compensation paid by the peer group to assess whether the ‘‘total cash compensation opportunities’’ that we provide to our executive officers are both competitive and commensurate with each executive officer’s position and corresponding duties. However, due to an overall increase in salaries in the New York area, the Committee may consider using the mean of the reported data as a benchmark in the future.
In establishing the executive compensation packages for fiscal 2007, the members of the Committee also focused on lessening the shortfalls between the compensation packages that we provide to our executive officers and the median compensation paid by the companies whose data underlie the Mercer benchmark database. The Committee does not, however, set specific percentile targets for total compensation of our executive officers compared to the total compensation of the peer group.
In making its decisions regarding our fiscal 2007 executive compensation packages, the Committee first reviewed the total cash compensation opportunities that we provided to our executive officers during fiscal 2006. Each executive officer’s ‘‘total cash compensation opportunities’’ consist of base salary, an annual cash bonus, and long-term incentives. The Committee then compared each executive officer’s total cash compensation opportunity to the total median cash compensation opportunity for the parallel position in the Mercer study. By focusing on each executive officer’s total cash compensation opportunities as a whole, instead of on single components of compensation such as base salary, the Committee created fiscal 2007 compensation packages for our executive officers that emphasize the performance-based components of compensation.
Role of Executive Officers and Compensation Committee in Compensation Process
The Committee establishes and enforces our general compensation philosophy in consultation with our Chief Executive Officer. The role of our Chief Executive Officer in the executive compensation process is to recommend individual pay adjustments for the executive officers, other than himself, to the Committee based on market conditions, our performance, and individual performance. With the assistance of our Vice President of Human Resources, our CEO presented the Committee with information comparing each executive officer’s compensation to the median compensation figures provided in the Mercer Database. Additionally, based on our budgeted fiscal 2007 financial performance, our CEO presented the Committee with budgeted EBITDA for purposes of setting the targets for our annual cash bonus plan.
Among other duties, the Committee has overall responsibility for:
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• Reviewing and approving compensation of our Chief Executive Officer, President, Chief Financial Officer and all other executive officers;
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• Reporting to the Board of Supervisors any and all decisions regarding compensation changes for our Chief Executive Officer, President, Chief Financial Officer and our other executive officers;
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• Evaluating and making recommendations to the Board of Supervisors regarding our annual bonus plan, long-term incentive plan, restricted unit plan, as well as all other compensation policies and programs;
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• Administering and interpreting the compensation plans that constitute each component of our executive officers’ compensation packages; and
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• Engaging consultants, when appropriate, to provide independent, third-party advice on executive officer-related compensation (in prior fiscal years, the Committee engaged Sibson Consulting during fiscal 2004 for benchmarking the fiscal 2005 executive officers’ compensation packages and Mercer during fiscal 2005 for benchmarking our President’s 2006 compensation package).
Allocation Among Components
Under our compensation structure, the mix of base salary, cash bonus and long-term compensation provided to each executive officer varies depending on their position. The base salary for each executive officer is the only fixed component of compensation. All other compensation, including annual cash bonuses and long-term incentive compensation, is variable in nature as it is dependent upon achievement of certain performance measures. The following table summarizes the components as percentages of each named executive officer’s total cash compensation opportunity.
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Base Salary
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Cash Bonus
Target![]()
Long-Term
Incentive Mark A. Alexander(1)![]()
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42 %
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42 %
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16 % Robert M. Plante
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42 %
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36 %
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22 % Michael J. Dunn, Jr.
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39 %
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39 %
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22 % Steven C. Boyd
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51 %
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31 %
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18 % Michael M. Keating
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49 %
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32 %
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19 % Jeffrey S. Jolly(2)
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46 %
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33 %
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21 %
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(1) Mr. Alexander’s Long-Term Incentive Plan award is considerably less than Mr. Plante’s and Mr. Dunn’s because under his employment agreement the percentage applied to his base pay is lower than the percentage applied to the base pay of each of the other named executive officers. (2) Pursuant to the terms of his severance agreement, in November 2007, Mr. Jolly was paid his Long-Term Incentive Plan award granted in fiscal 2005. Under the terms of this severance agreement, Mr. Jolly forfeited all rights to his 2006 and 2007 Long-Term Incentive Plan awards.
In allocating compensation among these elements, we believe that the compensation of our senior-most levels of management – the levels of management having the greatest ability to influence our performance – should be approximately 50% performance-based, while lower levels of management should receive a greater portion of their compensation in base salary. Additionally, our short-term and long-term incentive plans do not provide for minimum payments and are, thus, truly pay-for-performance compensation plans.
Internal Pay Equity
In determining the different compensation packages for each of our named executive officers, the Committee takes into consideration a number of factors, including the level of responsibility and influence that each named executive officer has over the affairs of the Partnership, tenure, individual performance and years in one’s current position. The relative importance assigned to each of these factors by the Committee may differ from executive to executive. The Committee will also consider
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Table of Contentsthe existing level of equity ownership of each of our named executive officers when granting awards under our 2000 Restricted Unit Plan and the 2003 Long-Term Incentive Plan (see below for a description of both plans). The compensation packages for our Chief Executive Officer and our President are set forth in their respective employment agreements, as further described below. As a result, different weight may be given to different components of compensation among each of our named executive officers. In addition, as discussed in the section above titled ‘‘Allocation Among Components,’’ the compensation packages that we provide to our senior-most levels of management are, at a minimum, 50% performance-based. In order to align the interests of senior management with the interests of our Common Unitholders, we consider it requisite to accentuate the performance-based elements of the compensation packages that we provide to these individuals because the actions and decisions of these individuals have a direct impact on our performance.
Base Salary
Base salaries for the named executive officers and, indeed, all of our other executive officers, are reviewed and approved annually by the Committee. In order to determine the fiscal 2007 base salary increases, the Committee compared each executive officer’s fiscal 2006 base salary with the corollary median salary provided in the Mercer study. The Committee determined base salary adjustments, which may be higher or lower than the comparative data, following an assessment of our overall results as well as each executive officer’s position, performance and scope of responsibility, while at the same time considering each executive officer’s previous total cash compensation opportunities. At the beginning of fiscal 2007, each named executive officer received adjustments to his base salary in accordance with the philosophy and process described above, ranging from 0% to 28%. A subsequent 8% adjustment was made to Mr. Boyd’s base salary upon his promotion to vice president during fiscal 2007. In the event of a promotion such as Mr. Boyd’s or a new hire, the Committee reviews and takes action at its next meeting.
The fiscal 2007 adjustments to each named executive officer’s base salary were as follows:
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Mark A. Alexander(1)
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0 % Robert M. Plante(2)
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28 % Michael J. Dunn, Jr.(3)
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7 % Steven C. Boyd(4)
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24 % Michael M. Keating
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9 % Jeffrey S. Jolly
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8 %
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(1) Because Mr. Alexander’s base salary is set forth under the provisions of his employment agreement, the Committee did not adjust his base salary. (2) The Committee’s decision to increase Mr. Plante’s salary by 28% was based on consideration of his responsibilities as CFO and the increasing complexity of the CFO’s responsibilities resulting from the promulgation of the Sarbanes-Oxley Act. (3) Upon the execution of an employment agreement with Mr. Dunn on February 5, 2007, his base salary was increased by 7% to $400,000. (4) This percentage represents the total adjustment between Mr. Boyd’s fiscal 2006 base salary and his base salary upon his promotion to vice president.
The total base salary paid to each named executive officer in fiscal 2007 is reported in the column titled ‘‘Salary ($)’’ in the Summary Compensation Table below.
Annual Cash Bonus Plan
Annual cash bonuses (which fall within the SEC’s definition of ‘‘Non-Equity Incentive Plan Compensation’’ for the purposes of the Summary Compensation Table and otherwise) are earned by our executive officers in accordance with the performance objective provisions of our annual cash
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Table of Contentsbonus plan. The cash bonuses earned by Mr. Alexander and Mr. Dunn are the only exceptions to this general rule because their bonus provisions are established in their respective employment agreements. Although this plan is generally administered using the formula described below, occasionally the Committee may exercise its broad discretionary powers to decrease or increase the annual cash bonus paid to a particular executive officer when the Committee recognizes that a particular executive officer’s performance warrants a decreased or an increased bonus. Such adjustments, if any, are recommended to the Committee by our Chief Executive Officer. During fiscal 2007, our Chief Executive Officer did not make any such recommendations to the Committee.
The terms of our annual bonus plan provide for cash payments of a specified percentage (which, in fiscal 2007, ranged from 60% to 100%) of our named executive officers’ annual base salaries (‘‘target cash bonus’’) if, for the fiscal year, actual EBITDA equals the Partnership’s budgeted EBITDA. For purposes of calculating the annual cash bonus, the Committee may exercise discretion to adjust both budgeted and actual EBITDA for various items considered to be non-recurring in nature; including, but not limited to, unrealized (non-cash) gains or losses from the application of SFAS 133 reported within cost of products sold in our statement of operations (‘‘cash bonus plan EBITDA’’). Executive officers have the opportunity to earn between 90% and 110% of their target cash bonuses, in accordance with the terms of the plan, paralleling the percentage of actual cash bonus plan EBITDA in relationship to budgeted cash bonus plan EBITDA ranging from 90% to 110%. Under the annual bonus plan, no bonuses are earned if actual cash bonus plan EBITDA is less than 90% of budgeted cash bonus plan EBITDA and cash bonuses cannot exceed 110% of the target cash bonus even if actual cash bonus plan EBITDA is more than 110% of budgeted cash bonus plan EBITDA.
For fiscal 2007, our budgeted cash bonus plan EBITDA was $171.7 million. Our actual cash bonus plan EBITDA was such that each of our executive officers earned 110% of his target cash bonus. The following table provides the fiscal 2007 budgeted cash bonus plan EBITDA targets that were established at the October 17, 2006 Compensation Committee meeting:
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Fiscal 2007 Budged Cash Bonus Plan EBITDA (in Millions)
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Target Bonus Percentage that
would have been Earned if
Actual Cash Bonus Plan
EBITDA Equaled the Figure
in the Previous Column $188.9![]()
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110 % $180.3
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105 % $171.7(1)
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100 % $163.1
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95 % $154.5
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90 %
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(1) Budgeted cash bonus plan EBITDA for fiscal 2007.
The bonuses earned under the annual cash bonus plan by each of our named executive officers are reported in the column titled ‘‘Non-Equity Incentive Plan Compensation ($)’’ in the Summary Compensation Table below.
The 2007 target cash bonus percentages and target cash bonuses established for each named executive officer and the actual cash bonuses earned by each of them during fiscal 2007 are summarized as follows:
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Name
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2007 Target
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2007 Target
Cash Bonus![]()
2007
Actual Cash
Bonus Earned Mark A. Alexander(1)![]()
![]()
![]()
100 %
![]()
![]()
$ 450,000
![]()
![]()
![]()
$ 495,000
Robert M. Plante
![]()
![]()
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85 %
![]()
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$ 255,000
![]()
![]()
![]()
$ 280,500
Michael J. Dunn, Jr.(1)(2)
![]()
![]()
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100 %
![]()
![]()
$ 400,000
![]()
![]()
![]()
$ 440,000
Steven C. Boyd(2)
![]()
![]()
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60 %
![]()
![]()
$ 141,000
![]()
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![]()
$ 155,100
Michael M. Keating
![]()
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65 %
![]()
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$ 136,500
![]()
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![]()
$ 150,150
Jeffrey S. Jolly(3)
![]()
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65 %
![]()
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$ 143,000
![]()
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$ 157,300
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(1) Mr. Alexander’s and Mr. Dunn’s target cash bonuses are established by the terms in their respective employment agreements. See ‘‘Employment Agreements’’ section below. (2) Both Mr. Dunn and Mr. Boyd received mid-year salary increases, and the Committee agreed to permit their target cash bonuses to equal their final salaries for the fiscal year multiplied by their respective target cash bonus percentages. (3) The terms of Mr. Jolly’s severance agreement permit, among other things, payment of his cash bonus, if earned in accordance with the terms of our annual bonus plan, as if he had remained in our employ during the entire 2007 fiscal year.
For purposes of establishing the cash bonus targets for fiscal 2008, at its meeting on October 31, 2007 the Committee reviewed and approved our fiscal 2008 budget. The budget is developed annually using a bottom-up process factoring in reasonable growth targets from the prior year performance, while at the same time attempting to reach a good balance between a target that is reasonably achievable, yet not assured. As described above, executive officers will have the opportunity to earn between 90% and 110% of their target cash bonuses, paralleling the percentage of actual cash bonus plan EBITDA in relationship to budgeted cash bonus plan EBITDA ranging from 90% to 110%. Over the past three years, our actual cash bonus plan EBITDA was such that each of our executive officers earned 110%, 109% and 0% of their respective target cash bonus for fiscal 2007, 2006 and 2005, respectively.
2003 Long-Term Incentive Plan
At the beginning of fiscal 2003, we adopted the 2003 Long-Term Incentive Plan (‘‘LTIP-2’’), a phantom unit plan, as a principal component of our executive compensation program. While the annual cash bonus plan is a pay-for-performance plan that focuses on our short-term financial goals, LTIP-2 is designed to motivate our executive officers to focus on long-term financial goals. LTIP-2 measures the market performance of our Common Units on the basis of total return to our Unitholders (‘‘TRU’’) during a three-year measurement period commencing on the first day of the fiscal year in which an unvested award was granted and compares our TRU to the TRU of each of the other members of a predetermined peer group, primarily consisting of other master limited partnerships, approved by the Committee. The predetermined peer group may vary from year-to-year, but for all current awards, includes Amerigas, Ferrellgas and Inergy (the other propane master limited partnerships). Unvested awards are granted at the beginning of each fiscal year as a Committee-approved percentage of each executive officer’s salary. Cash payouts, if any, are earned and paid at the end of the three-year measurement period.
LTIP-2 is designed to:
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• Align a portion of our executive officers’ compensation opportunities with the long-term goals of our Unitholders;
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• Provide long-term compensation opportunities consistent with market practice;
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• Reward long-term value creation; and
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• Provide a retention incentive for our executive officers and other key employees.
At the beginning of the three-year measurement period, each executive officer’s unvested grant of phantom units is calculated by dividing a predetermined percentage (which is 30% for Mr. Alexander and for all other executive officers is 52%), established upon adoption of LTIP-2, of the executive officer’s target bonus by the average of the closing prices of our Common Units for the twenty days preceding the beginning of the fiscal year. At the end of the three-year measurement period, depending on the quartile ranking within which our TRU falls relative to the other members of the peer group, our executive officers, as well as the other participants, all of whom are key employees, will receive a cash payout equal to:
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• The quantity of the participant’s phantom units multiplied by the average of the closing prices of our Common Units for the twenty days preceding the conclusion of the three-year measurement period;
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• The quantity of the participant’s phantom units multiplied by the sum of the distributions that would have inured to one of our outstanding Common Units during the three-year measurement period; and
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• The sum of the products of the two preceding calculations multiplied by: zero if our performance falls within the lowest quartile of the peer group; 50% if our performance falls within the second lowest quartile; 100% if our performance falls within the second highest quartile; and 125% if our performance falls within the top quartile.
The three-year measurement period of the fiscal 2005 award ended simultaneously with the conclusion of fiscal 2007. The TRU for the fiscal 2005 award fell within the second highest quartile. The following is a summary of the cash payouts related to the fiscal 2005 award earned by our named executive officers at the conclusion of fiscal 2007.
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Mark A. Alexander
![]()
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$ 206,923
Robert M. Plante
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$ 143,499
Michael J. Dunn, Jr.
![]()
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$ 239,112
Steven C. Boyd
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$ 70,349
Michael M. Keating
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$ 95,877
Jeffrey S. Jolly
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$ 103,647
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The following is a summary of the quantity of phantom units that signify the unvested grants to our named executive officers during fiscal years 2006 and 2007 that will be used to calculate cash payments at the end of each respective award’s three-year measurement period (i.e., at the end of our fiscal year 2008 for the fiscal 2006 award and at the end of our fiscal year 2009 for the fiscal 2007 award).
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![]()
Fiscal Year
2006 Award![]()
Fiscal Year
2007 Award Mark A. Alexander![]()
![]()
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4,328
![]()
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4,007
Robert M. Plante
![]()
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3,134
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3,936
Michael J. Dunn, Jr.
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6,252
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5,788
Steven C. Boyd
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1,645
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2,037
Michael M. Keating
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2,092
![]()
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2,107
Jeffrey S. Jolly
![]()
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-0-
![]()
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-0-
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The peer group members selected by the Committee for the fiscal 2005 award comprised both energy and pipeline-related publicly-traded partnerships as well as two energy-related corporations because the Committee believed it reasonable to measure our performance against the performance of a peer group consisting of diverse energy providers. The following table lists, in alphabetical order, the names and ticker symbols of the peer group used to measure our performance during the fiscal 2005 LTIP-2 award’s three-year measurement period:
2005 LTIP-2 Award Peer Group
(Three-year Measurement Period Completed)
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Peer Group Member Name
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Ticker Symbol AmeriGas Partners, L.P.
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APU CH Energy Group, Inc.
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CNG Energy Transfer Partners, L.P.
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ETP Enterprise Products Partners, L.P.
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EDP Ferrellgas Partners, L.P.
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FGP Inergy, L.P.
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NRGY Kinder Morgan Energy Partners, L.P.
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KMP Oneok Partners, L.P.
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OKS Piedmont Natural Gas Co., Inc.
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PNY Plains All American Pipeline, L.P.
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PAA Star Gas Partners, L.P.
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SGU
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Table of ContentsThe peer group members selected by the Committee for the fiscal 2006 and fiscal 2007 awards were somewhat different because the Committee decided that the peer group should consist entirely of publicly-traded partnerships, inclusive of all propane-related partnerships. The Committee decided this because all publicly-traded partnerships have similar tax attributes and can, as a result, distribute more cash than similarly-sized corporations generating similar revenues. The following table lists, in alphabetical order, the names and ticker symbols of the peer group used to measure our performance during the fiscal 2006 and fiscal 2007 LTIP-2 awards’ three-year measurement periods:
2006 and 2007 LTIP-2 Awards Peer Group
(Completed Two Years and Three Years of Each Award’s
Three-year Measurement Period, Respectively)
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Peer Group Member Name
![]()
Ticker Symbol AmeriGas Partners, L.P.
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APU Copano Energy, LLC
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CPNO Crosstex Energy, L.P.
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XTEX Dorchester Minerals, L.P.
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DMLP Energy Transfer Partners, L.P.
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ETP Ferrellgas Partners, L.P.
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FGP Inergy, L.P.
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NRGY MarkWest Energy Partners, L.P.
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MWE Plains All American Pipeline, L.P.
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PAA Star Gas Partners, L.P.
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SGU Sunoco Logistics Partners, L.P.
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SXL
The LTIP-2 document also contains a retirement provision that provides for the immediate termination of the three-year measurement period for all outstanding LTIP-2 awards held by a participant upon retirement. TRU is calculated as if the three-year measurement period for each outstanding award ended on the participant’s retirement date in order to determine whether a payment has been earned by the retiree.
Because LTIP-2 is a phantom unit plan, compensation expense generated by this plan is charged to earnings in accordance with SFAS 123R. As a result, all such charges to this year’s earnings relative to our named executive officers are reported in the column titled ‘‘Unit Awards ($)’’ in the Summary Compensation Table below.
2000 Restricted Unit Plan
We adopted the 2000 Restricted Unit Plan (‘‘RUP’’) effective November 1, 2000. Upon adoption, this plan authorized the issuance of 487,805 Common Units to our executive officers, managers and other employees and to the members of our Board of Supervisors. On October 17, 2006, following approval by our Unitholders, we adopted amendments to the RUP which, among other things, increased the number of Common Units authorized for issuance under the RUP by 230,000 for a total of 717,805. At the conclusion of fiscal 2007, there remained 71,792 restricted units available for future grants.
When the Committee authorizes a grant of restricted units, the unvested units underlying a grant do not provide the grantee with voting rights and do not pay or accrue distributions during the vesting period. Restricted unit grants vest as follows: 25% on the third and fourth anniversaries of the grant date and the remaining 50% on the fifth anniversary of the grant date. Unvested grants are subject to forfeiture in certain circumstances as defined in the RUP document. Upon vesting, restricted units are automatically converted into our Common Units, with full voting rights and rights to receive distributions.
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Table of ContentsThe RUP document contains a retirement provision that provides for the immediate vesting of all unvested RUP grants held by a retiring participant who meets all three of the following conditions on his or her retirement date:
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1. The unvested RUP grant has been held by the grantee for at least six months;
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2. The RUP grantee is age 55 or older; and
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3. The RUP grantee has worked for us or one of our predecessors for at least 10 years.
On October 31, 2007, in order to comply with the regulations promulgated under Internal Revenue Code (‘‘IRC’’) Section 409(A), the Board of Supervisors amended the retirement provision to require a six-month delay between a retirement eligible RUP participant’s retirement date and the date on which the Partnership issues outstanding Common Units to such Participants.
All RUP grants are made at the discretion of the Committee. Although the reasons for awarding a grant can vary, the objective of awarding a grant to a recipient is twofold: to retain the services of the recipient over the five-year vesting period while, at the same time providing the type of motivation that further aligns the long-term interests of the recipient with the long-term interests of our Unitholders. The reasons for which the Committee awards RUP grants include, but are not limited to, the following:
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• To attract skilled and capable candidates to fill vacant positions;
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• To retain the services of an employee;
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• To provide an adequate compensation package to accompany an internal promotion; and
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• To reward outstanding performance.
In determining the quantity of restricted units to award to each executive officer and other key employees, the Committee considers, without limitation:
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• The executive officer’s scope of responsibility, performance and contribution to meeting our objectives;
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• The total cash compensation opportunity provided to the executive officer for whom the grant is being considered;
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• The value of similar equity awards to executive officers of similarly sized enterprises; and
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• The current value of a similar quantity of outstanding Common Units.
In addition, in establishing the level of restricted units to grant to our executive officers, the Committee considers the level of equity ownership by our executive officers and, prior to October 17, 2006, the level of equity representation through management’s ownership of the General Partner.
Our practice is to determine the dollar amount of equity compensation that we want to provide. This dollar amount is then converted into a quantity of restricted units by dividing that dollar amount by the average of the closing prices of our Common Units for the twenty trading days preceding the grant date. The Committee generally makes these awards at their first meeting each year following the availability of the financial results for the prior fiscal year; however, occasionally the Committee grants awards at other times of the year, particularly when the need arises to grant awards because of promotions and new hires. The grant date for RUP grants coincides with the date of grant by the Committee typically at its October or November meeting. However, in the few cases that grants were approved at other Committee meetings during the year, the effective date of the grant invariably coincided with the date of the meeting.
On October 31, 2007, the Committee adopted a policy with respect to the effective date of subsequent grants of restricted units under the RUP which states that:
Unless the Committee expressly determines otherwise for a particular award at the time of its approval of such award, the effective date of grant of all awards of restricted units under the
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Table of ContentsRUP in a given calendar year will be the first business day in the month of December of that calendar year. If, at the discretion of the Committee, an award is expressed as a dollar amount, then such award will be converted into the number of restricted units, as of the effective date of grant, obtained by dividing the dollar amount of the award by the average of the closing prices, on the New York Stock Exchange, of one Common Unit of the Partnership for the 20 trading days immediately prior to that effective date of grant.
During fiscal 2007, RUP grants were awarded to the following named executive officers:
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Grant Date
![]()
Quantity of
Restricted Units Robert M. Plante![]()
November 1, 2006
![]()
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![]()
2,753
Steven C. Boyd
![]()
April 25, 2007
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5,496
Michael M. Keating
![]()
April 25, 2007
![]()
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![]()
2,198
![]()
Mr. Plante’s and Mr. Keating’s RUP grants were awarded to them by the Committee in recognition of their exemplary performance over the past ten years. Mr. Boyd’s RUP grant was awarded in recognition of his performance and promotion to vice president.
Compensation expense for unvested RUP grants is recognized ratably over the vesting periods and is net of estimated forfeitures in accordance with SFAS 123R. The RUP-related SFAS 123R expense recognized in the Partnership’s fiscal 2007 statement of operations, excluding forfeiture estimates, on behalf of each of the named executive officers is reported in the column titled ‘‘Unit Awards ($)’’ in the Summary Compensation Table below.
Recoupment of Incentive Compensation
On April 25, 2007, upon recommendation by the Committee, the Board of Supervisors approved an Incentive Compensation Recoupment Policy which permits the Committee to seek the reimbursement from certain executives of the Partnership and Operating Partnership of incentive compensation paid to those executives in connection with any fiscal year for which there is a significant restatement of the published financial statements of the Partnership triggered by a material accounting error, which results in less favorable results than those originally reported by the Partnership. Such reimbursement can be sought from executives even if they had no responsibility for the restatement. In addition to the foregoing, if the Committee determines that any fraud or intentional misconduct by an executive was a contributing factor to the Partnership having to make a significant restatement, then the Committee is authorized to take appropriate action against such executive, including disciplinary action, up to, and including, termination, and requiring reimbursement of all, or any part, of the compensation paid to that executive in excess of that executive’s base salary, including cancellation of any unvested restricted units. The Incentive Compensation Recoupment Policy is available on our website at www.suburbanpropane.com.
On July 31, 2007, the Board amended the annual bonus plan, LTIP-2 and the RUP to expressly make future awards under such plans subject to the Incentive Compensation Recoupment Policy.
Long-Term Incentive Plan of October 1, 1997
Effective October 1, 1997, we adopted a non-qualified, unfunded long-term incentive plan for executive officers and other key employees (‘‘LTIP-1’’). Effective September 30, 2004, we discontinued LTIP-1 with the effect that no new awards will be made after that date; however, all awards for which the performance criteria had been satisfied prior thereto will continue to vest and be payable in accordance with their terms. LTIP-1 awards were based on a percentage of base salary and were subject to the achievement of certain performance criteria, including our ability to earn sufficient funds to make cash distributions on our Common Units with respect to the fiscal years for which the awards were granted. Because all performance criteria for LTIP-1 were satisfied during the fiscal years for which any outstanding awards were granted, the Summary Compensation Table below contains only interest credits made in accordance with the terms of the plan in the column titled ‘‘Non-Equity Incentive Plan Compensation ($).’’ Because the Committee authorized a November 2007 payment of
68
Table of Contentsall remaining plan balances to the remaining participants, the amounts reported in the Summary Compensation Table below represent the final interest credits that we will provide to the participants on behalf of this plan.
Originally, awards vested over a five-year period with one-third vesting at the beginning of each of years three, four, and five following the award date. Prior to the enactment of IRC Section 409(A) on January 1, 2005, payments relating to unvested awards earned prior to September 30, 2004 under LTIP-1 were expected to be made annually through the end of fiscal 2011. On November 2, 2005, our Board of Supervisors approved amendments to LTIP-1 for the purpose of IRC Section 409(A) compliance. The principal amendments provided:
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• That all previously vested amounts under LTIP-1 as of the date of the amendment were to be distributed to participants by December 31, 2005;
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• That all future vested amounts will be distributed to plan participants within 30 days after such amounts become vested; and
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• That future deferrals of awards under LTIP-1 are no longer permitted.
Pension Plan
We sponsor a noncontributory defined benefit pension plan that was originally designed to cover all of our eligible employees who met certain criteria relative to age and length of service. Effective January 1, 1998, we amended the plan in order to provide for a cash balance format rather than the final average pay format that was in effect prior to January 1, 1998. The cash balance format is designed to evenly spread the growth of a participant’s earned retirement benefit throughout his or her career rather than the final average pay format, under which a greater portion of a participant’s benefits were earned toward the latter stages of his or her career. Effective January 1, 2000, we amended the plan to limit inclusion in this plan to existing participants and no longer admit new participants to the plan. On January 1, 2003, we amended the plan to cease future service credits on behalf of the participants and, from that point on, participants’ benefits have earned only interest credits toward their ultimate retirement benefit.
Each of our named executive officers participates in the plan. The changes in the actuarial value relative to each named executive officer’s participation in the plan is reported in the column titled ‘‘Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)’’ in the Summary Compensation Table below.
Deferred Compensation
All employees, including the named executive officers, who satisfy certain service requirements, are entitled to participate in our IRC Section 401(k) Plan (the ‘‘401(k) Plan’’), in which participants may defer a portion of their eligible cash compensation up to the limits established by law. We offer the 401(k) plan to attract and retain talented employees by providing them with a tax-advantaged opportunity to save for retirement.
For fiscal 2007, all of our named executive officers participated in the 401(k) Plan. The benefits provided to our named executive officers under the 401(k) Plan are provided on the same basis as to our other exempt employees. Amounts deferred by our named executive officers under the 401(k) Plan are included in the column titled ‘‘Salary ($)’’ in the Summary Compensation Table below.
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Table of ContentsIn order to be competitive with other employers, if certain performance criteria are met, we will provide our employee-participants with a match of up to 6% of their base salary that was contributed to the plan during the calendar year. The following chart shows the performance target criteria that must be met for each level of matching contribution:
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![]()
If We Meet This Percentage of Budgeted EBITDA(1)
![]()
The Participating Employee
Will Receive this Matching
Contribution for the Year 115% or higher![]()
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100 % 100% to 114%
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50 % 90% to 99%
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25 % Less than 90%
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0 %
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(1) For additional information regarding the non-GAAP term ‘‘Budgeted EBITDA,’’ refer to the explanation provided under the subheading ‘‘Annual Cash Bonus Plan’’ above.
For fiscal 2007, our budgeted 401(k) Plan EBITDA was $171.7 million. Our fiscal 2007 results were such that actual 401(k) Plan EBITDA exceeded 115% of budgeted 401(k) Plan EBITDA. As a result, we shall provide participants with a match equal to 100% of their calendar year 2007 contributions that did not exceed 6% of their total base pay up to the statutory maximum of $15,500. The matching contributions that we will make on behalf of our named executive officers are reported in the column titled ‘‘All Other Compensation ($)’’ in the Summary Compensation Table below.
Non-Qualified Deferred Compensation
We maintain a Non-Qualified Deferred Compensation Plan (the ‘‘Compensation Deferral Plan’’) to which vested Restricted Units from the 1996 Restricted Unit Plan (which was subsequently replaced by the 2000 Restricted Unit Plan described above) were deferred on May 26, 1999 in connection with our Recapitalization. The Compensation Deferral Plan is structured as a rabbi trust. On November 2, 2005, for the purpose of IRC Section 409(A) compliance, our Board of Supervisors approved an amendment to the Compensation Deferral Plan that prohibited any additional deferral elections.
Presently, Mr. Alexander and Mr. Dunn are the only remaining beneficiaries of the Compensation Deferral Plan. In accordance with their deferral elections, the entire corpus of the Compensation Deferral Plan shall be distributed to them during January 2008 and the fair market value of their respective portions of the corpus shall be added to their taxable wage earnings for that calendar year.
Because the Compensation Deferral Plan contains only Common Units, and because the cash distributions that inure to those units are immediately distributed to the beneficiaries, the plan does not provide Mr. Alexander and Mr. Dunn with above market interest; nor do they receive distributions on the Common Units at a rate higher than the distributions paid on behalf of our Common Units held by the investing public. As a result, nothing relative to the Compensation Deferral Plan is reported in the Summary Compensation Table below.
Supplemental Executive Retirement Plan
In 1998, we adopted a non-qualified, unfunded supplemental retirement plan known as the Suburban Propane Company Supplemental Executive Retirement Plan (the ‘‘SERP’’). The purpose of the SERP is to provide Mr. Alexander and Mr. Dunn with a level of retirement income from us, without regard to statutory maximums, including the IRC’s limitation for defined benefit plans. In light of the conversion of the Pension Plan to a cash balance formula as described under the subheading ‘‘Pension Plan’’ above, the SERP was amended and restated effective January 1, 1998. The annual retirement benefit under the SERP represents the amount of annual benefits that the participants in the SERP would otherwise be eligible to receive, calculated using the same pay-based credits referenced in the ‘‘Pension Plan’’ section above, applied to the amount of annual compensation that exceeds the IRC’s statutory maximums for defined benefit plans, which was $200,000 in 2002. Effective
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Table of ContentsJanuary 1, 2003, the SERP was discontinued with a frozen benefit determined for Mr. Alexander and Mr. Dunn. Provided that the SERP requirements are met, upon retirement Mr. Alexander will receive a monthly benefit of $6,737 and Mr. Dunn will receive a monthly benefit of $373. Because this plan does not provide Mr. Alexander and Mr. Dunn with above market interest credits, nothing relative to the SERP is reported in the Summary Compensation Table below.
Other Benefits
As part of his total compensation package, each named executive officer is eligible to participate in all of our other employee benefit plans, such as the medical, dental, group life insurance and disability plans. In each case, with the exception of Mr. Alexander for whom we purchase supplemental life insurance and supplemental long-term disability policies at a cost of $6,249 per year, these benefits are provided on the same basis as are provided to other exempt employees. These benefit plans are offered to attract and retain talented employees and to provide them with competitive benefits.
Other than to Mr. Alexander and Mr. Dunn, in accordance with the terms of their employment agreements (described below), there are no post-termination or other special rights provided to any named executive officer to participate in these benefit programs other than the right to participate in such plans for a fixed period of time following termination of employment as required by law.
The costs of all such benefits incurred on behalf of our named executive officer’s are reported in the column titled ‘‘All Other Compensation ($)’’ in the Summary Compensation Table below.
Perquisites
Perquisites represent a minor component of our executive officers’ compensation. Each of the named executive officers is eligible for tax preparation services, a company-provided vehicle, and an annual physical. The following table summarizes both the value and the utilization of these perquisites by the named executive officers.
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Name
![]()
Tax
Preparation
Services![]()
Employer-
Provided
Vehicle![]()
Physical Mark A. Alexander
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$ 2,000
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$ 11,078
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$ 1,200
Robert M. Plante
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$ 2,000
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$ 10,349
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$ 1,200
Michael J. Dunn, Jr.
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$ 2,000
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$ 10,198
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$ 1,200
Steven C. Boyd
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$ 950
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$ 5,647
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$ -0-
Michael M. Keating
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$ 2,000
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$ 11,522
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$ 1,500
Jeffrey S. Jolly
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$ 2,000
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$ -0-
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$ 1,200
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Perquisite-related costs are reported in the column titled ‘‘All Other Compensation ($)’’ in the Summary Compensation Table below.
Impact of Accounting and Tax Treatments of Executive Compensation
As we are a partnership and not a corporation for federal income tax purposes, we are not subject to the executive compensation tax deductible limitations of IRC Section 162(m). Accordingly, none of the compensation paid to our named executive officers is subject to limitation. However, if such tax laws related to executive compensation change in the future, the Committee will consider the implications on us.
In accordance with their respective employment agreements, Mr. Alexander and Mr. Dunn are entitled to receive tax gross-up payments for any parachute excise tax incurred pursuant to IRC Section 4999; they are also entitled to receive tax gross-up payments for any payment that violates the provisions of IRC Section 409(A) or its associated regulations.
On November 2, 2005, the Board of Supervisors approved an amendment to the Suburban Propane, L.P. Severance Protection Plan for Key Employees (the ‘‘Severance Plan’’) to provide that if
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Table of Contentsany payment under the Severance Plan subjects a participant to the 20% federal excise tax under IRC Section 409(A), the payment will be grossed up to permit such participant to retain a net amount on an after-tax basis equal to what he or she would have received had the excise tax not been payable.
Employment Agreements
Mr. Alexander, our Chief Executive Officer, and Mr. Dunn, our President, are the only named executive officers, and, indeed, the only executive officers, with whom we have employment agreements. We entered into an employment agreement with Mr. Alexander when it was announced, on March 5, 1996, that he would become our Chief Executive Officer. This agreement was subsequently amended on October 23, 1997, April 14, 1999 and November 2, 2005. We entered into an employment agreement that had an effective date of February 1, 2007 with Mr. Dunn on February 5, 2007.
Mr. Alexander’s Employment Agreement had an initial term of three years, and automatically renews for successive one-year periods, unless earlier terminated by us or by Mr. Alexander or otherwise terminated in accordance with the terms of the employment agreement. The employment agreement provides for an annual base salary of $450,000 as of September 30, 2006 and provides Mr. Alexander with the opportunity to earn a cash bonus of up to 100% of base salary based upon the achievement of the same EBITDA-related performance criteria as contained in our annual cash bonus plan described in the section titled ‘‘Annual Cash Bonus Plan’’ above. Under our partnership agreement, the Committee has the authority to grant Mr. Alexander a bonus in excess of 100% if, in accordance with the terms of the annual bonus plan, our other executive officers earn bonuses exceeding their target bonuses for the fiscal year. The Committee exercised this authority in connection with Mr. Alexander’s cash bonus for fiscal 2006 and fiscal 2007. The discretionary component of Mr. Alexander’s fiscal 2007 cash bonus is disclosed in the column titled ‘‘Bonus ($)’’ and the non-discretionary component of Mr. Alexander’s bonus is disclosed in the column titled ‘‘Non-Equity Incentive Plan Compensation ($)’’ in the Summary Compensation Table below.
Mr. Alexander’s employment agreement also provides for the opportunity to participate in benefit plans made available to our other executive officers and our other key employees. We also provide Mr. Alexander with a term life insurance policy with a face amount equal to three times his base salary.
If a change of control (as defined in the ‘‘Change of Control’’ section below) of the Partnership occurs, and within six months prior thereto or at any time subsequent to such change of control, we terminate Mr. Alexander’s employment without cause (as defined in the ‘‘Severance Benefits’’ section below) or if Mr. Alexander resigns with good reason (as defined in the ‘‘Severance Benefits’’ section below) or terminates his employment commencing on the six month anniversary and ending on the twelve month anniversary of such change of control, then Mr. Alexander shall be entitled to:
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• A lump sum severance payment equal to three times his annual base salary in effect as of the date of termination plus three times his annual cash bonus at 100%; and
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• Medical benefits for three years from the date of such termination.
In situations unconnected to a change of control event, if the Partnership terminates Mr. Alexander’s employment without cause or if Mr. Alexander resigns with good reason, then Mr. Alexander shall be entitled to:
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• A severance payment equal to (A) the portion of his base salary earned but not paid as of the date of termination, (B) his pro-rata annual cash bonus under the employment agreement based upon the number of days worked during the fiscal year of termination, and (C) three times his annual base salary in effect as of the date of termination; and
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• Medical benefits for three years from the date of such termination reduced to the extent comparable benefits are provided to Mr. Alexander by another party.
The employment agreement requires that if any payment received by Mr. Alexander is subject to either or both of the 20% excise taxes under IRC Sections 4999 and 409(A), the payment shall be
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Table of Contentsincreased to permit Mr. Alexander to retain a net amount on an after-tax basis equal to what he would have received had the excise tax not been payable.
If Mr. Alexander’s employment is terminated due to death, disability, without good reason, or pursuant to delivery of a non-renewal notice to the Partnership in accordance with the terms and conditions of his employment agreement, he or his estate, as the case may be, shall be entitled to earned but unpaid base salary plus his pro-rata cash bonus. If his employment is terminated by the Partnership for cause, he shall be entitled to his earned but unpaid base salary only.
Mr. Dunn’s employment agreement has an initial term of two years commencing on February 1, 2007, the term of which shall automatically renew for successive one-year periods, unless earlier terminated by us or by Mr. Dunn or otherwise terminated in accordance with the terms of the employment agreement. The provisions of Mr. Dunn’s employment agreement provide for an initial annual base salary of $400,000 per year (pro-rated in the case of the Partnership’s 2007 fiscal year and any other partial fiscal year during the term of the employment agreement) and, in accordance with the provisions of our annual cash bonus plan, the opportunity to earn a cash bonus in each fiscal year up to 110% of his annual base salary for that same fiscal year (the ‘‘Maximum Annual Cash Bonus’’). Additionally, Mr. Dunn’s employment agreement permits him to participate in the same benefit plans made available to our other executive officers and other key employees.
If a change of control (as defined in the ‘‘Change of Control’’ section below) of the Partnership occurs and within six months prior thereto or within two years thereafter the Partnership terminates Mr. Dunn’s employment without cause (as defined in the ‘‘Severance Benefits’’ section below) or if Mr. Dunn resigns with good reason (as defined in the ‘‘Severance Benefits’’ section below), then Mr. Dunn shall be entitled to a severance payment equal to the sum of:
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• The portion of his base salary earned but not paid as of the date of termination;
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• His pro-rata cash bonus (the bonus Mr. Dunn would have been entitled to under the employment agreement for the full fiscal year in which the termination occurred multiplied by the number of days from the beginning of that fiscal year until the termination date and divided by 365);
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• Two times the sum of (1) his annual base salary in effect as of the date of termination, plus (2) the Maximum Annual Cash Bonus; and
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• Medical benefits for two years from the date of such termination.
In situations unconnected to a change of control event, if the Partnership terminates Mr. Dunn’s employment without cause, or if Mr. Dunn resigns with good reason, then Mr. Dunn shall be entitled to:
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• A severance payment equal to (A) the portion of his base salary earned but not paid as of the date of termination, (B) the annual cash bonus Mr. Dunn would have been entitled to under the employment agreement for the full fiscal year in which the termination occurred had Mr. Dunn remained employed by the Partnership for that full fiscal year, and (C) two times his annual base salary in effect as of the date of termination; and
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• Medical benefits for two years from the date of such termination.
The employment agreement requires that if any payment received by Mr. Dunn is subject to either or both of the 20% excise taxes under IRC Sections 4999 and 409(A), the payment shall be increased to permit Mr. Dunn to retain a net amount on an after-tax basis equal to what he would have received had the excise tax not been payable.
If Mr. Dunn’s employment is terminated due to death, disability, or pursuant to delivery of a non-renewal notice to the Partnership in accordance with the terms and conditions of his employment agreement, he or his estate, as the case may be, shall be entitled to earned but unpaid base salary plus his pro-rata cash bonus for the fiscal year during which termination occurred. If his employment is terminated by the Partnership for cause, or he resigns without good reason, he shall be entitled to his earned but unpaid base salary only.
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Table of ContentsFor additional information, see the table titled ‘‘Potential Payments Upon Termination’’ below.
Severance Benefits
We believe that, in most cases, employees should be paid reasonable severance benefits. Therefore, it is the general policy of the Committee to provide executive officers and other key employees who are terminated by us without cause or who choose to terminate their employment with us for good reason with a severance payment equal to, at a minimum, one year’s base salary, unless circumstances dictate otherwise. This policy was adopted because it may be difficult for former executive officers and other key employees to find comparable employment within a short period of time. However, depending upon individual facts and circumstances, particularly the severed employee’s tenure with us, the Committee permits us to provide additional severance to severed executive officers and other key employees.
A ‘‘key employee’’ is an employee who has attained a director level pay-grade or higher. ‘‘Cause’’ will be deemed to exist where the individual has been convicted of a crime involving moral turpitude, has stolen from us, has violated his or her non-competition or confidentiality obligations, or has been grossly negligent in fulfillment of his or her responsibilities. ‘‘Good reason’’ generally will exist where an executive officer’s position or compensation has been decreased or where the employee has been required to relocate.
Change of Control
Our executive officers and other key employees have built Suburban Propane Partners, L.P. into the successful enterprise that it is today; therefore, we believe that it is important to protect them in the event of a change of control. Further, it is our belief that the interests of our Unitholders will be best served if the interests of our executive officers are aligned with them, and that providing change of control benefits should eliminate, or at least reduce, the reluctance of our executive officers to pursue potential change of control transactions that may be in the best interests of our Unitholders. Additionally, we believe that the severance benefits provided to our executive officers and to our key employees are consistent with market practice and appropriate because these benefits are an inducement to accepting employment and because the executive officers have agreed to and are subject to non-competition and non-solicitation covenants for a period following termination of employment. Therefore, our executive officers and other key employees are provided with employment protection following a change of control (the ‘‘Severance Protection Plan’’). Our Severance Protection Plan covers all executive officers, including the named executive officers, with the exception of our Chief Executive Officer and our President, whose severance provisions are established in their respective employment agreements.
The Severance Protection Plan provides for severance payments between sixty-five to seventy-eight weeks of base salary and target cash bonuses for such officers and key employees following a change of control and termination of employme