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. Under the agreement for the Agway Acquisition, the seller was required to deposit $15.0 million from the total purchase price into an escrow account to reimburse us for any such future environmental costs and expenses. The escrowed funds were to be used to fund such environmental costs and expenses during the first three years following the closing date of the Agway Acquisition.

Since the Agway Acquisition and through February 2006, $10.1 million of the escrowed funds were utilized to fund environmental remediation expenditures. On March 17, 2006, we finalized an agreement with the seller for the release of the remaining escrowed funds to us and, as such, received $4.9 million which will be used to fund our estimated future remediation and monitoring costs. Based on management’s estimate of required future remediation and monitoring activities, the remaining funds are expected to be sufficient to cover future requirements after considering expected reimbursement from state environmental agencies. As of September 30, 2006, we had accrued environmental liabilities of $4.8 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 $1.3 million as of September 30, 2006.

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

National Fire Protection Association (‘‘NFPA’’) Pamphlet Nos. 54 and 58, which establish rules and procedures governing the safe handling of propane, or comparable regulations, have been adopted, in whole, in part or with state addenda, as the industry standard for propane storage, distribution and equipment installation and operation in all of the states in which we operate. In some states these laws are administered by state agencies, and in others they are administered on a municipal level. Pamphlet No. 58 has adopted storage tank valve retrofit requirements due to be completed by June 2011 or later depending on when each state adopts the 2001 edition of NFPA Pamphlet No. 58. We have a program in place to meet this deadline.

NFPA Pamphlet Nos. 30, 30A, 31, 385 and 395, which establish rules and procedures governing the safe handling of distillates (fuel oil, kerosene and diesel fuel) and gasoline, or comparable regulations, have been adopted, in whole, in part or with state addenda, as the industry standard for fuel oil, kerosene, diesel fuel and gasoline storage, distribution and equipment installation/operation in all of the states in which we 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

10

Table of Contents

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.

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 30, 2006, we had 3,441 full time employees, of whom 363 were engaged in general and administrative activities (including fleet maintenance), 44 were engaged in transportation and product supply activities and 3,034 were customer service center employees. As of September 30, 2006, 111 of our employees were represented by 11 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.

11

---

Table of Contents

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 reserves. Because they are not dependent on profitability, which is affected by non-cash items, our cash distributions might be made during periods when we record losses and might not be made during periods when we record profits.

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

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

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

	•	issuances of debt and equity securities;

	•	our ability to control expenses;

	•	fluctuations in working capital;

	•	capital expenditures; and

	•	financial, business and other factors, a number 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 30, 2006, we had total outstanding borrowings of $548.3 million, including $423.3 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 a significant 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.

12

---

Table of Contents

Unitholders have limited voting rights.

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

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

Some provisions of our Partnership Agreement may discourage, delay or prevent third parties from acquiring us, even if doing so would be beneficial to our Unitholders. For example, our Partnership Agreement contains a provision, based on Section 203 of the Delaware General Corporation Law, that generally prohibits the Partnership from engaging in a business combination with a 15% or greater Unitholder for a period of three years following the date that person or entity acquired at least 15% of our outstanding Common Units, unless certain exceptions apply. Additionally, our Partnership Agreement sets forth advance notice procedures for a Unitholder to nominate a Supervisor to stand for election, which procedures may discourage or deter a potential 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:

	•	a court or government agency determined that we were conducting business in the state but had not complied with the state’s limited partnership statute; or

	•	Unitholders’ rights to act together to remove or replace the General Partner or take other actions under our Partnership Agreement are deemed to constitute ‘‘participation in the control’’ of our business for purposes of the state’s limited partnership statute.

Unitholders may have liability to repay distributions.

Unitholders will not be liable for assessments in addition to their initial capital investment in the Common Units. Under specific circumstances, however, Unitholders may have to repay to us amounts wrongfully returned or distributed to them. Under Delaware law, we may not make a distribution to Unitholders if the distribution causes our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and nonrecourse liabilities are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that a limited partner who receives a distribution of this kind and knew at the time of the distribution that the distribution violated Delaware law will be liable to the limited partnership for the distribution amount for three years from the distribution date. Under Delaware law, an assignee who becomes a substituted limited partner of a limited partnership is liable for the obligations of the assignor to make contributions to the partnership. However, such an assignee is not obligated for liabilities unknown to him at the time he or she became a limited partner if the liabilities could not be determined from the partnership agreement.

13

---

Table of Contents

If we issue additional limited partner interests or other equity securities as consideration for acquisitions or for other purposes, the relative voting strength of each Unitholder will be diminished over time due to the dilution of each Unitholder’s interests and additional taxable income may be allocated to each Unitholder.

Our Partnership Agreement generally allows us to issue additional limited partner interests and other equity securities without the approval of our Unitholders. Therefore, when we issue additional Common Units or securities ranking on a parity with the Common Units, each Unitholder’s proportionate partnership interest will decrease, and the amount of cash distributed on each Common Unit and the market price of Common Units could decrease. The issuance of additional Common Units will also diminish the relative voting strength of each previously outstanding Common Unit. In addition, the issuance of additional Common Units will, over time, result in the allocation of additional taxable income, representing built-in gain 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 11% warmer than normal for the year ended September 30, 2006 compared to 6% warmer than normal in the prior year, as reported by the National Oceanic and Atmospheric Administration (‘‘NOAA’’). During the critical heating months of January and February 2006, average temperatures were 20% warmer than normal. 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

14

---

Table of Contents

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 overall demand for fuel oil to be relatively flat to moderately declining during the same period. Year-to-year industry volumes of propane and fuel oil are expected to be primarily affected by weather patterns and from competition intensifying during warmer than normal winters.

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 multistate 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.

The 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

15

---

Table of Contents

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.

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. Future technological advances in heating, conservation and energy generation may adversely affect our financial condition and results of operations.

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 our 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

16

---

Table of Contents

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 unrelated business taxable income and thus will be taxable to the Unitholder. Distributions to foreign persons will be reduced by withholding taxes at the highest applicable effective tax rate, and foreign persons will be required to file United States federal tax returns and pay tax on their share of our taxable income.

17

---

Table of Contents

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.

There are state, local and other tax considerations for our Unitholders.

In addition to United States federal income taxes, Unitholders will likely be subject to other taxes, such as state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, even if

18

---

Table of Contents

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.

19

---

Table of Contents

ITEM 1B.	UNRESOLVED STAFF COMMENTS

None.

ITEM 2.	PROPERTIES

As of September 30, 2006, we owned approximately 76% 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 and a 60 million gallon underground propane storage cavern in Tirzah, South Carolina. Additionally, we own our principal executive offices located in Whippany, New Jersey.

The transportation of propane requires specialized equipment. The trucks and railroad tank cars utilized for this purpose carry specialized steel tanks that maintain the propane in a liquefied state. As of September 30, 2006, we had a fleet of 17 transport truck tractors, of which we owned three, and 22 railroad tank cars, of which we owned two. In addition, as of September 30, 2006 we had 1,072 bobtail and rack trucks, of which we owned approximately 16%, 207 fuel oil tankwagons, of which we owned approximately 61%, and 1,691 other delivery and service vehicles, of which we owned approximately 41%. We lease the vehicles we do not own. As of September 30, 2006, we also owned approximately 871,509 customer propane storage tanks with typical capacities of 100 to 500 gallons, 189,247 customer propane storage tanks with typical capacities of over 500 gallons and 239,512 portable propane cylinders with typical capacities of five to ten gallons.

ITEM 3.	LEGAL PROCEEDINGS

Litigation

Our operations are subject to all operating hazards and risks normally incidental to handling, storing and delivering combustible liquids such as propane. As a result, we have been, and will continue to be, a defendant in various legal proceedings and litigation arising in the ordinary course of business. We are self-insured for general 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 $45.4 million at September 30, 2006), 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 $8.7 million at September 30, 2006).

On October 21, 2004 the jury in the trial of Heritage Propane Partners, L.P. v. SCANA et al. returned a unanimous verdict in our favor on all claims pending against us by Heritage Propane Partners, L.P. (‘‘Heritage’’). Following our Operating Partnership’s 1999 acquisition of the propane assets of SCANA Corporation (‘‘SCANA’’), Heritage had brought an action in the South Carolina Court of Common Pleas for Richland County against SCANA for breach of contract and fraud and against our Operating Partnership for tortious interference with contract and tortious interference with prospective contract. After the jury returned a verdict against SCANA, the Court conducted a separate bench trial on our cross-claims against SCANA for indemnification, in which we sought to recover our defense costs. The Court granted judgment on our cross-claims against SCANA and awarded us a total of approximately $2.6 million. However, on November 17, 2005, the Court granted SCANA’s motion to vacate the judgment in our favor. SCANA claimed that, at the time that the order was entered, the Court lacked jurisdiction over our cross-claims because SCANA had appealed the jury verdict against it, thereby divesting the Court of jurisdiction over matters that could be affected by SCANA’s appeal. SCANA further claimed that if the judgment against it was vacated on appeal, it would have no liability to us for our defense costs. We were informed that Heritage has

20

---

Table of Contents

settled its claims against SCANA on appeal and that SCANA and Heritage are in the process of requesting a dismissal of the appeal. In order to avoid the uncertainties of result and the additional expenses that would be associated with continuing this litigation, on November 2, 2006 we agreed to settle this matter with SCANA. In connection with this settlement, SCANA paid us $2.0 million.

ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

The 2006 Tri-Annual Meeting of the Partnership’s Unitholders (the ‘‘Tri-Annual Meeting’’) was held on October 17, 2006. Pursuant to authority granted by the Unitholders, after the votes were counted on all but one of the proposals described below, the Board of Supervisors adjourned the Tri-Annual Meeting until October 19, 2006, at which time the votes were counted on the last proposal.

At the Tri-Annual Meeting, the Unitholders re-elected to the Board of Supervisors, for a three-year term, all three nominees proposed by the Board:

Nominee			For						Withheld
John Hoyt Stookey					28,650,048						529,165
Harold R. Logan, Jr.					28,566,429						612,784
Dudley C. Mecum					28,649,329						529,884

Pursuant to the Previous Partnership Agreement which was in effect at the time of the Tri-Annual Meeting, the General Partner had the right to appoint two of the five Supervisors of the Partnership. The General Partner appointed Mark A. Alexander and Michael J. Dunn, Jr. as Supervisors. Pursuant to amendments to the Previous Partnership Agreement approved by the Unitholders at the Tri-Annual Meeting and implemented at the closing of the GP Exchange Transaction, Messrs. Alexander and Dunn will serve as Supervisors until the next Tri-Annual Meeting of Unitholders (scheduled to be held in 2009), at which meeting all Supervisors will be elected by the Unitholders.

At the Tri-Annual Meeting, the Unitholders also approved the following proposals:

The exchange of 2,300,000 Common Units for the IDRs and economic interests in the Partnership and the Operating Partnership held by the General Partner (see ‘‘GP Exchange Transaction and Amendment to Partnership Agreements’’ in Item 1 of this Annual Report and Note 19 to the Consolidated Financial Statements included in this Annual Report):

			For						Against						Abstain						Broker Non-Votes
All Common Units					15,342,742						1,028,541						431,001						12,376,929
Common Units held by Unaffiliated Unitholders*					15,267,609						1,028,541						431,001						12,376,929

*	Unaffiliated Unitholders are all Unitholders other than the individual members of the General Partner prior to the consummation of the GP Exchange Transaction.

The amendment of the Previous Partnership Agreement to effect the GP Exchange Transaction, to provide for the election of all Supervisors by the Unitholders and other changes (as described in Item 1 of this Annual Report):

			For						Against						Abstain						Broker Non-Votes
All Common Units					15,406,367						914,978						480,939						12,376,929
Common Units held by Unaffiliated Unitholders					15,331,234						914,978						480,939						12,376,929

21

---

Table of Contents

The amendment of the Previous Partnership Agreement to restrict combinations with interested Unitholders, based on Section 203 of the Delaware General Corporation Law:

			For						Against						Abstain						Broker Non-Votes
All Common Units					15,538,338						818,878						445,068						12,376,929
Common Units held by Unaffiliated Unitholders					15,463,204						818,878						445,068						12,376,929

The amendment of the Previous Partnership Agreement to require a 66-2/3% vote to change the procedure set forth in the Partnership Agreement to nominate Supervisors:

			For						Against						Abstain						Broker Non-Votes
All Common Units					15,257,345						1,265,643						378,730						12,307,359
Common Units held by Unaffiliated Unitholders					15,182,212						1,265,643						378,730						12,307,359

The Partnership’s 2000 Restricted Unit Plan, as amended and restated, including the authorization of 230,000 additional Common Units to be available for grant under the plan:

			For						Against						Abstain						Broker Non-Votes
All Common Units					14,961,298						1,398,320						442,666						12,402,205

Adjournment of the Tri-Annual Meeting, if necessary, to solicit additional proxies:

			For						Against						Abstain						Broker Non-Votes
All Common Units					27,555,354						1,167,792						453,416						—

22

---

Table of Contents

PART II

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

(a) Our Common Units, representing limited partner interests in the Partnership, are listed and traded on the New York Stock Exchange (‘‘NYSE’’) under the symbol SPH. As of December 7, 2006, there were 895 Common Unitholders of record. The following table presents, for the periods indicated, the high and low sales prices per Common Unit, as reported on the NYSE, and the amount of quarterly cash distributions declared and paid per Common Unit with respect to each quarter.

			Common Unit Price Range												Cash Distribution Paid per Common Unit
			High						Low
Fiscal 2005
First Quarter				$	35.70					$	30.00					$	0.6125
Second Quarter					36.00						33.45						0.6125
Third Quarter					35.70						31.55						0.6125
Fourth Quarter					37.40						25.39						0.6125
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

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) with respect to such quarter. Available Cash generally means all cash on hand at the end of the fiscal quarter plus all additional cash on hand as a result of borrowings subsequent to the end of such quarter less cash reserves established by the Board of Supervisors in its reasonable discretion for future cash requirements.

We are a publicly traded limited partnership and, other than certain corporate subsidiaries, we are not subject to federal income tax. Instead, Unitholders are required to report their allocable share of our earnings or loss, regardless of whether we make distributions.

	(b)	Not applicable.

	(c)	None.

23

---

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.

			Year Ended
			September 30, 2006 (a)						September 24, 2005						September 25, 2004 (b)						September 27, 2003						September 28, 2002
Statement of Operations Data
Revenues				$	1,661,640					$	1,620,234					$	1,307,254					$	735,075					$	635,122
Costs and expenses					1,523,380						1,548,436						1,231,356						655,225						552,341
Restructuring costs (c)					6,076						2,775						2,942						—						—
Impairment of goodwill (d)					—						656						3,177						—						—
Gain on sale of storage facility					—						—						—						—						(6,768	)
Income before interest expense, loss on debt extinguishment and provision for income taxes (e)					132,184						68,367						69,779						79,850						89,549
Loss on debt extinguishment (f)					—						36,242						—						—						—
Interest expense, net					40,680						40,374						40,832						33,629						35,325
Provision for income taxes					764						803						3						202						703
Income (loss) from continuing operations (e)					90,740						(9,052	)					28,944						46,019						53,521
Discontinued operations:
Gain on sale of customer service centers (g)					—						976						26,332						2,483						—
(Loss) income from discontinued customer service centers					—						—						(972	)					167						3
Net income (loss) (e)					90,740						(8,076	)					54,304						48,669						53,524
Income (loss) from continuing operations per Common Unit – basic					2.84						(0.29	)					0.96						1.77						2.12
Net income (loss) per Common Unit – basic (h)					2.84						(0.26	)					1.79						1.87						2.12
Net income (loss) per Common Unit – diluted (h)					2.83						(0.26	)					1.78						1.86						2.12
Cash distributions declared per unit				$	2.53					$	2.45					$	2.41					$	2.33					$	2.28
Balance Sheet Data (end of period)
Cash and cash equivalents				$	60,571					$	14,411					$	53,481					$	15,765					$	40,955
Current assets					235,351						236,803						252,894						98,912						116,789
Total assets					953,886						965,597						992,007						670,559						700,146
Current liabilities, excluding short-term borrowings and current portion of long-term borrowings					192,616						194,987						202,024						94,802						98,606
Total debt					548,304						575,295						515,915						383,826						472,769
Other long-term liabilities					112,265						119,199						105,950						107,853						109,485
Partners’ capital – Common Unitholders					170,151						159,199						238,880						165,950						103,680
Partner’s (deficit) capital – General Partner				$	(1,969	)				$	(1,779	)				$	852					$	1,567					$	1,924

24

---

Table of Contents

			Year Ended
			September 30, 2006 (a)						September 24, 2005						September 25, 2004 (b)						September 27, 2003						September 28, 2002
Statement of Cash Flows Data
Cash provided by (used in)
Operating activities				$	170,321					$	39,005					$	93,065					$	57,300					$	68,775
Investing activities					(19,092	)					(24,631	)					(196,557	)					(4,859	)					(6,851	)
Financing activities				$	(105,069	)				$	(53,444	)				$	141,208					$	(77,631	)				$	(57,463	)
Other Data
Depreciation and amortization				$	33,151					$	37,762					$	36,743					$	27,520					$	28,355
EBITDA and Adjusted EBITDA (i)					165,335						107,105						131,882						110,020						117,907
Capital expenditures – maintenance and growth (j)					23,057						29,301						26,527						14,050						17,464
Acquisitions				$	—					$	—					$	211,181					$	—					$	—
Retail gallons sold
Propane					466,779						516,040						537,330						491,451						455,988
Fuel oil and refined fuels					145,616						244,536						220,469						—						—

(a)	Fiscal 2006 includes 53 weeks of operations compared to 52 weeks in each of fiscal 2005, 2004, 2003 and 2002.

(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 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 included in the all other segment.

(e)	These amounts include, in addition to the gain on sale of customer service centers and the gain on sale of storage facility, gains from the disposal of property, plant and equipment of $1.0 million for fiscal 2006, $2.0 million for fiscal 2005, $0.7 million for fiscal 2004, $0.6 million for fiscal 2003 and $0.5 million for fiscal 2002.

(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 sale of customer service centers 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 sale of customer service centers for fiscal 2004 of $26.3 million reflects the sale of 24 customer service centers for net cash proceeds of approximately $39.4 million. Gain on sale of customer service centers for fiscal 2003 of $2.5 million reflects the sale of nine customer service centers for net cash proceeds of approximately $7.2 million. The gains on sale have been accounted for within discontinued operations pursuant to Statement of Financial Accounting

25

---

Table of Contents

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 in fiscal 2004 have been reclassified to remove financial results from continuing operations. Prior period results of operations attributable to the customer service centers sold in fiscal 2003 were not significant and, as such, results prior to fiscal 2003 were not reclassified to remove financial results from continuing operations.

(h)

Computations of earnings per Common Unit are 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 is allocated to the Common Unitholders and the General Partner in accordance with their respective partnership ownership interests, after giving effect to any priority income allocations for IDRs of the General Partner. Following the GP Exchange Transaction consummated on October 19, 2006, the two-class method of computing income per Common Unit under EITF 03-6 will no longer be 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 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, September 27, 2003 or September 28, 2002.

Basic income per Common Unit for the year ended September 30, 2006 is computed by dividing the limited partners’ share of net income, calculated under the two-class method of computing earnings, by the weighted average number of outstanding Common Units. 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 ‘‘Earnings per Share’’ (‘‘SFAS 128’’). Basic net income (loss) per Common Unit for the years ended September 24, 2005, September 25, 2004, September 27, 2003 and September 28, 2002 is 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 is computed by dividing net income (loss), after deducting our General Partner’s interest, by the weighted average number of outstanding Common Units and time vested restricted units granted under our 2000 Restricted Unit Plan.

(i)

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 not 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

26

---

Table of Contents

	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):

			Fiscal 2006						Fiscal 2005						Fiscal 2004						Fiscal 2003						Fiscal 2002
Net income (loss)				$	90,740					$	(8,076	)				$	54,304					$	48,669					$	53,524
Add:
Provision for income taxes					764						803						3						202						703
Interest expense, net					40,680						40,374						40,832						33,629						35,325
Depreciation and amortization					33,151						37,762						36,743						27,520						28,355
EBITDA					165,335						70,863						131,882						110,020						117,907
Loss on debt extinguishment					—						36,242						—						—						—
Adjusted EBITDA					165,335						107,105						131,882						110,020						117,907
Add (subtract):
Provision for income taxes					(764	)					(803	)					(3	)					(202	)					(703	)
Loss on debt extinguishment					—						(36,242	)					—						—						—
Interest expense, net					(40,680	)					(40,374	)					(40,832	)					(33,629	)					(35,325	)
Gain on disposal of property, plant and equipment, net					(1,000	)					(2,043	)					(715	)					(636	)					(546	)
Gain on sale of customer service centers					—						(976	)					(26,332	)					(2,483	)					—
Gain on sale of storage facility					—						—						—						—						(6,768	)
Changes in working capital and other assets and liabilities					47,430						12,338						29,065						(15,770	)					(5,790	)
Net cash provided by (used in)
Operating activities				$	170,321					$	39,005					$	93,065					$	57,300					$	68,775
Investing activities				$	(19,092	)				$	(24,631	)				$	(196,557	)				$	(4,859	)				$	(6,851	)
Financing activities				$	(105,069	)				$	(53,444	)				$	141,208					$	(77,631	)				$	(57,463	)

(j)	Our capital expenditures fall generally into two categories: (i) maintenance expenditures, which include expenditures for repair and replacement of property, plant and equipment; and (ii) growth capital expenditures which include new propane tanks and other equipment to facilitate expansion of our customer base and operating capacity.

27

---

Table of Contents

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

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 volatile changes as a result of product supply or other market conditions, including, but not limited to, economic and political factors impacting crude oil and natural gas supply or pricing. Product cost changes can occur rapidly over a short period of time and can impact profitability. There is no assurance that we will be able to pass on product cost increases fully or immediately, particularly when product costs increase rapidly. Therefore, average retail sales prices can vary significantly from year to year as product costs fluctuate with propane, fuel oil, crude oil and natural gas commodity market conditions. In addition, in periods of sustained higher commodity prices, as was experienced over the past two 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 rely heavily on propane, fuel oil or natural gas as a heating source. Accordingly, the volume sold is directly affected by the severity of the winter weather in our service areas, which can vary substantially from year to year. In any given area, sustained warmer than normal temperatures will tend to result in reduced propane, fuel oil and natural gas consumption, while sustained colder than normal temperatures will tend to result in greater use.

Risk Management

Product supply contracts are generally one-year agreements subject to annual renewal and generally permit suppliers to charge posted market prices (plus transportation costs) at the time of delivery or the current prices established at major delivery points. Since rapid increases in the cost of propane or fuel oil may not be immediately passed on to retail customers, such increases could reduce profitability. We engage in risk management activities to reduce the effect of price volatility on our

28

---

Table of Contents

product costs and to help ensure the availability of product during periods of short supply. We are currently a party to propane and fuel oil futures contracts traded on the NYMEX and enter into forward and option agreements with third parties to purchase and sell propane at fixed prices in the future. Risk management activities are monitored by an internal Commodity Risk Management Committee, made up of five members of management, through enforcement of our Hedging and Risk Management Policy and reported to our Audit Committee. Risk management transactions may not always result in increased product margins. See Item 7A of this Annual Report.

Critical Accounting Policies and Estimates

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. We believe that the following are our critical accounting estimates:

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

Pension and Other Postretirement Benefits.    We estimate the rate of return on plan assets, the discount rate to estimate the present value of future benefit obligations and the cost of future health care benefits in determining our annual pension and other postretirement benefit costs. In accordance with GAAP, actual results that differ from our assumptions are accumulated and amortized over future periods and therefore, generally affect our recognized expense and recorded obligation in such future periods. While we believe that our assumptions are appropriate, significant differences in our actual experience or significant changes in market conditions may materially affect our pension and other postretirement 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

29

---

Table of Contents

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

We reported record earnings for the fiscal year ended September 30, 2006 despite a challenging operating environment resulting from the combination of significantly warmer than normal temperatures and sustained high energy costs resulting in continued customer conservation. Net income for fiscal 2006 of $90.7 million, or $2.84 per Common Unit, increased $98.8 million compared to a net loss of $8.1 million, or $0.26 per Common Unit, in the prior year. EBITDA (as defined and reconciled below) amounted to $165.3 million in fiscal 2006, an increase of $58.2 million (54.3%) compared to Adjusted EBITDA (which excludes a $36.2 million loss on debt extinguishment as defined and reconciled below) of $107.1 million in fiscal 2005. Fiscal 2006 includes 53 weeks of operations compared to 52 weeks in the prior year.

The significant improvement in year-over-year financial results reflects the positive steps taken since the beginning of the fourth quarter of fiscal 2005, and throughout fiscal 2006, to streamline our field operating footprint, drive operational efficiencies and cost savings and improve our customer mix by exiting certain lower margin business. In addition to the field realignment efforts, during the third quarter of fiscal 2006 we initiated plans to restructure our HVAC service offerings and reduce the level of HVAC installation activities. The focus of our ongoing service offerings will be in support of our existing customer base within our propane, fuel oil and refined fuels and natural gas and electricity segments. Since our field realignment process began, we have eliminated more than 400 positions and retired nearly 700 vehicles from our fleet, generating significant savings in our fixed cost structure. During fiscal 2006, while we did not experience the full-year effect of the cost savings from these initiatives, savings in payroll and benefit related expenses, costs to operate and maintain our fleet and other costs to operate our customer service centers exceeded $27.0 million.

Another contributing factor to our increased earnings compared to the prior year was the impact on profitability in the fuel oil and refined fuels segment from the decision to eliminate the fuel oil Ceiling Program following the fiscal 2005 heating season. As reported throughout fiscal 2005, our margin opportunities in the fuel oil business were restricted as a result of a fuel oil Ceiling Program which pre-established a maximum price per gallon, coupled with our decision not to hedge when confronted with unprecedented costs to hedge the program. The impact of the lost margin opportunity on our prior year results was approximately $21.5 million. By eliminating this pricing program for

30

---

Table of Contents

fiscal 2006, we no longer incur the costs of hedging deliveries associated with the Ceiling Program and we have been successful in implementing our market-based pricing strategies without significant customer losses.

In our propane and refined fuels segments, while significantly warmer than normal temperatures and continued high commodity prices have had a negative effect on volumes sold, our continued efforts to strategically exit certain lower margin business accounted for a significant portion of the volume decline, yet favorably impacted overall segment profitability. 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 25.5 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 51.8 million gallons in fiscal 2006 compared to the prior year. Overall, propane volumes sold in fiscal 2006 of 466.8 million gallons decreased 49.2 million gallons (9.5%) compared to 516.0 million gallons in fiscal 2005. Fuel oil and refined fuels volumes sold of 145.6 million gallons in fiscal 2006 decreased 98.9 million gallons (40.4%) compared to 244.5 million gallons in the prior year.

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 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 2006 in line with the reduction in headcount; and (iv) a $2.0 million charge included within cost of products sold to reduce the carrying value of inventory that will no longer be marketed by our customer service centers as a result of our reorganization.

By comparison, Adjusted EBITDA and net loss for fiscal 2005 were unfavorably impacted by $3.5 million and $39.7 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; and (iii) a $0.7 million charge attributable to impairment of goodwill associated with our HVAC segment.

As a result of the timing of our field realignment efforts and the restructuring of our HVAC segment, we expect additional cost savings during fiscal 2007 from the full-year effect of these initiatives. With the positive steps taken over the past year to further streamline our operating cost structure, drive operational efficiencies and improve our customer mix, we believe we are well positioned for supporting the growth of our core operating segments and for profitable growth into the future. Additionally, with the consummation of the GP Exchange Transaction on October 19, 2006, we have simplified our capital structure by eliminating our General Partner’s disproportionate 15% share of future distribution growth in exchange for the issuance of 2,300,000 Common Unit representing approximately 7% of the total outstanding Common Units. As a result, 100% of all future distribution increases, if any, will inure to the benefit of our Common Unitholders (including the current and former members of management who owned the General Partner).

From a cash flow perspective, we generated cash flow from operating activities of $170.3 million in fiscal 2006, an increase of $131.3 million compared to the prior year, and ended the fiscal year with more than $60.0 million in cash on hand and no amounts outstanding under the working capital facility of our Revolving Credit Agreement. As we look ahead to fiscal 2007, our anticipated cash requirements include: (i) maintenance and growth capital expenditures of approximately $25.0 million; (ii) approximately $41.0 million of interest and income tax payments; and, (iii) assuming distributions remain at the current level, approximately $86.4 million of distributions to Common Unitholders (an increase of approximately $2.6 million as a result of the issuance of Common Units in the GP Exchange Transaction). Based on our current estimate of our cash position, availability under the

31

---

Table of Contents

Revolving Credit Agreement (unused borrowing capacity under the working capital facility of $125.9 million at December 7, 2006) 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 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.

Revenues

(Dollars in thousands)			Fiscal 2006						Fiscal 2005						Increase / (Decrease)						Percent Increase / (Decrease)
Revenues
Propane				$	1,086,083					$	969,943					$	116,140						12.0	%
Fuel oil and refined fuels					356,531						431,223						(74,692	)					(17.3	%)
Natural gas and electricity					122,071						102,803						19,268						18.7	%
HVAC					87,258						106,115						(18,857	)					(17.8	%)
All other					9,697						10,150						(453	)					(4.5	%)
Total revenues				$	1,661,640					$	1,620,234					$	41,406						2.6	%

Total revenues increased $41.4 million, or 2.6%, to $1,661.6 million for the year ended September 30, 2006 compared to $1,620.2 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 $1,086.1 million for the year ended September 30, 2006 increased $116.1 million, or 12.0%, compared to $969.9 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

32

---

Table of Contents

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 fuel oil 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 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

(Dollars in thousands)			Fiscal 2006						Fiscal 2005						Increase / (Decrease)						Percent Increase / (Decrease)
Cost of products sold
Propane				$	635,365					$	545,677					$	89,688						16.4	%
Fuel oil and refined fuels					272,052						385,501						(113,449	)					(29.4	%)
Natural gas and electricity					102,687						90,461						12,226						13.5	%
HVAC					35,972						42,650						(6,678	)					(15.7	%)
All other					5,721						5,456						265						4.9	%
Total cost of products sold				$	1,051,797					$	1,069,745					$	(17,948	)					(1.7	%)
As a percent of total revenues					63.3	%					66.0	%

The cost of products sold reported in the consolidated statements of operations represents the weighted average unit cost of propane and fuel oil sold, as well as the cost of natural gas and electricity, including transportation costs to deliver product from our supply points to storage or to our customer service centers. Cost of products sold also includes the cost of appliances and related parts sold or installed by our customer service centers computed on a basis that approximates the average cost of the products. Changes in the fair value of derivative instruments that are not designated as hedges are recorded in current period earnings 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 $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

33

---

Table of Contents

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 fuel oil 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 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

(Dollars in thousands)			Fiscal 2006						Fiscal 2005						Decrease						Percent Decrease
Operating expenses				$	374,871					$	393,738					$	(18,867	)					(4.8	%)
As a percent of total revenues					22.6	%					24.3	%

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

Operating expenses of $374.9 million for the year ended September 30, 2006 decreased $18.9 million, or 4.8%, compared to $393.7 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 $10.5 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

34

---

Table of Contents

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

(Dollars in thousands)			Fiscal 2006						Fiscal 2005						Increase						Percent Increase
General and administrative expenses				$	63,561					$	47,191					$	16,370						34.7	%
As a percent of total revenues					3.8	%					2.9	%

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 $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 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.

Depreciation and Amortization

(Dollars in thousands)			Fiscal 2006						Fiscal 2005						Decrease						Percent Decrease
Depreciation and amortization				$	33,151					$	37,762					$	(4,611	)					(12.2	%)
As a percent of total revenues					2.0	%					2.3	%

Depreciation and amortization expense for the year ended September 30, 2006 decreased $4.6 million, or 12.2%, 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

(Dollars in thousands)			Fiscal 2006						Fiscal 2005						Increase						Percent Increase
Interest expense, net				$	40,680					$	40,374					$	306						0.8	%
As a percent of total revenues					2.4	%					2.5	%

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.

35

---

Table of Contents

Discontinued Operations.    During fiscal 2005, we recorded a gain on sale of $1.0 million to reflect the finalization of certain purchase price adjustments with the buyer of the customer service centers sold in fiscal 2004.

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 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.

36

---

Table of Contents

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:    

			Year Ended
(Dollars in thousands)			September 30, 2006						September 24, 2005
Net income (loss)				$	90,740					$	(8,076	)
Add:
Provision for income taxes					764						803
Interest expense, net					40,680						40,374
Depreciation and amortization					33,151						37,762
EBITDA					165,335						70,863
Loss on debt extinguishment					—						36,242
Adjusted EBITDA					165,335						107,105
Add (subtract):
Provision for income taxes					(764	)					(803	)
Loss on debt extinguishment					—						(36,242	)
Interest expense, net					(40,680	)					(40,374	)
Gain on disposal of property, plant and equipment, net					(1,000	)					(2,043	)
Gain on sale of customer service centers					—						(976	)
Changes in working capital and other assets and liabilities					47,430						12,338
Net cash provided by (used in)
Operating activities				$	170,321					$	39,005
Investing activities				$	(19,092	)				$	(24,631	)
Financing activities				$	(105,069	)				$	(53,444	)

Fiscal Year 2005 Compared to Fiscal Year 2004

Revenues

(Dollars in thousands)			Fiscal 2005						Fiscal 2004						Increase						Percent Increase
Revenues
Propane				$	969,943					$	856,109					$	113,834						13.3	%
Fuel oil and refined fuels					431,223						281,682						149,541						53.1	%
Natural gas and electricity					102,803						68,452						34,351						50.2	%
HVAC					106,115						92,072						14,043						15.3	%
All other					10,150						8,939						1,211						13.5	%
Total revenues				$	1,620,234					$	1,307,254					$	312,980						23.9	%

Total revenues increased $313.0 million, or 23.9%, to $1,620.2 million for the year ended September 24, 2005 compared to $1,307.3 million for the year ended September 25, 2004 driven primarily by a significant increase in average selling prices in line with higher product costs, the inclusion of the Agway Energy operations for a full twelve months in fiscal 2005 compared to nine months in the prior year, offset to an extent by the impact on volumes from warmer weather. Retail sales volumes in our propane and fuel oil segments were negatively impacted by a combination of warmer than normal average nationwide temperatures, as well as the impact of customer conservation efforts from the significant rise in energy costs. As reported by NOAA, average nationwide temperatures in both fiscal 2005 and 2004 were 7% warmer than normal. However, the fiscal 2005 heating season presented a very erratic weather pattern with significantly warmer than normal temperatures during the critical months of the heating season (November 2004 through

37

---

Table of Contents

February 2005) offset somewhat by a burst of cold weather in March 2005. Average nationwide temperatures were 9% warmer than normal during these critical months in fiscal 2005.

Revenues in our propane segment of $969.9 million for the year ended September 24, 2005 increased $113.8 million, or 13.3%, compared to $856.1 million in the prior year. This increase is the result of higher average selling prices in line with higher commodity prices, offset to an extent by lower retail sales volumes attributable to the combination of warmer weather and customer conservation. Retail propane gallons sold decreased 21.3 million gallons, or 4.0%, to 516.0 million gallons in fiscal 2005 from 537.3 million gallons in the prior year. Average retail selling prices increased approximately 16.8% as a result of sustained higher commodity prices for propane. The average posted price of propane during fiscal 2005 increased approximately 26% compared to the average posted prices in the prior year. Additionally, included within the propane segment are revenues from wholesale and risk management activities of $37.0 million for the year ended September 24, 2005 which decreased $6.0 million, or 14.0%, compared to the prior year.

Revenues from the distribution of fuel oil and refined fuels of $431.2 million for the year ended September 24, 2005 increased $149.5 million, or 53.1%, from $281.7 million in the prior year from a combination of increased volumes and significantly higher selling prices. Sales of fuel oil and refined fuels amounted to 244.5 million gallons during fiscal 2005 compared to 220.5 million gallons in the prior year, an increase of 24.0 million gallons, or 10.9%, primarily reflecting the impact of the Agway Energy operations for a full twelve months in fiscal 2005 compared to nine months in the prior year, offset to an extent by the impact of warm weather and customer conservation. In addition, during the fourth quarter of fiscal 2004, we exited certain lower margin low sulfur diesel and gasoline businesses, thus negatively impacting the year-over-year volume comparison. Average fuel oil posted prices increased even more dramatically than propane prices throughout fiscal 2005 reaching unprecedented levels into the third and fourth quarters. For the year, average posted price of fuel oil increased 54% compared to the average posted prices in fiscal 2004. Average fuel oil selling prices increased approximately 28.6% as we were unable to pass on fully the significant rise in the commodity prices as a result of the fuel oil Ceiling Program (see below for the impact on cost of products sold).

Revenues in our natural gas and electricity segment for the year ended September 24, 2005 increased $34.4 million, or 50.2%, to $102.8 million compared to $68.5 million in the prior year. The increase is primarily attributable to higher average selling prices for both natural gas and electricity in line with higher product costs, as well as the impact of a full twelve months of operations in fiscal 2005. Revenues in our HVAC segment increased 15.3%, to $106.1 million in fiscal 2005 compared to $92.1 million in the prior year. The increase in HVAC revenues reflects the impact of a full twelve months from the Agway Energy operations, offset to an extent by lower service and installation activities during the last nine months of fiscal 2005 compared to the prior year.

Cost of Products Sold

(Dollars in thousands)			Fiscal 2005						Fiscal 2004						Increase / (Decrease)						Percent Increase / (Decrease)
Cost of products sold
Propane				$	545,677					$	453,599					$	92,078						20.3	%
Fuel oil and refined fuels					385,501						228,155						157,346						69.0	%
Natural gas and electricity					90,461						59,950						30,511						50.9	%
HVAC					42,650						36,267						6,383						17.6	%
All other					5,456						5,581						(125	)					(2.2	%)
Total cost of products sold				$	1,069,745					$	783,552					$	286,193						36.5	%
As a percent of total revenues					66.0	%					59.9	%

Cost of products sold increased $286.2 million, or 36.5%, to $1,069.7 million for the year ended September 24, 2005 compared to $783.5 million in the prior year. The increase results primarily from higher commodity prices for propane and fuel oil, coupled with the full year impact of the Agway

38

---

Table of Contents

Energy operations. Cost of products sold for fiscal 2005 include a $2.5 million unrealized (non-cash) loss representing the net change in fair values of derivative instruments during the period, compared to a $4.5 million unrealized loss in the prior year (see Item 7A 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 $545.7 million increased $92.1 million, or 20.3%, compared to the prior year. Higher propane prices resulted in a $112.3 million increase in cost of products sold during fiscal 2005 compared to the prior year, partially offset by the 4.0% decline in propane volumes which had an impact of $15.9 million. Lower wholesale and risk management activities, noted above, decreased cost of products sold by $3.7 million compared to the prior year.

Cost of products sold associated with our fuel oil and refined fuels segment of $385.5 million for the year ended September 24, 2005 increased $157.3 million, or 69.0%, compared to the prior year. The impact of the unprecedented high commodity prices increased cost of products sold by $134.6 million during fiscal 2005 compared to the prior year and the increased volumes had an impact of $24.3 million. Cost of products sold in the prior year also included a $6.3 million non-cash charge associated with the settlement of futures contracts that were acquired in the Agway Acquisition. As the underlying futures and option contracts were settled, the derivative assets were charged to cost of products sold as an offset to the realized gains from contract settlement. The impact on cost of products sold represented a non-cash charge resulting from the application of purchase accounting on derivative instruments acquired.

While revenues increased 53.1%, margin opportunities and therefore profitability in our fuel oil and refined fuels segment were significantly restricted during our second and third quarters of fiscal 2005 as a result of our fuel oil Ceiling Program. We were unable in the prevailing high price environment to pass on fully the rise in fuel oil prices due to the restrictions of our fuel oil Ceiling Program, which pre-established a maximum price per gallon, coupled with our decision not to hedge this pricing program for the February through April deliveries when confronted with unprecedented costs to properly hedge the program during that period. The lost margin opportunity from this fuel oil Ceiling Program had the most significant negative impact on our financial results for fiscal 2005 accounting for an estimated impact of $21.5 million on the year-over-year comparison of operating margins in the fuel oil and refined fuels segment. After evaluating the costs to adequately hedge this program in the current price environment, management decided to discontinue offering the fuel oil Ceiling Program after the fiscal 2005 heating season. Cost of products sold as a percentage of revenues in our fuel oil and refined fuels segment increased from 81.0% during fiscal 2004 to 89.4% in fiscal 2005 primarily as a result of our inability to pass on fully the unprecedented rise in fuel oil prices, coupled with the fact that February through April 2005 deliveries under the Ceiling Program were not hedged as the costs to hedge continued to be prohibitive due to market volatility.

In addition, the increase in revenues attributable to our natural gas and electricity and HVAC business segments had a $30.5 million and $6.4 million impact, respectively, on cost of products sold for the year ended September 24, 2005 compared to the prior year. Higher natural gas and electricity costs and higher volumes were the main attributes for the increase in our natural gas and electricity segment.

For the year ended September 24, 2005, cost of products sold represented 66.0% of revenues compared to 59.9% in the prior year. This increase results primarily from the impact of the fuel oil operations described above, as well as the continued impact of product mix with a full year of the non-propane Agway Energy operations.

39

---

Table of Contents

Operating Expenses

(Dollars in thousands)			Fiscal 2005						Fiscal 2004						Increase						Percent Increase
Operating expenses				$	393,738					$	357,173					$	36,565						10.2	%
As a percent of total revenues					24.3	%					27.3	%

Operating expenses of $393.7 million for the year ended September 24, 2005 increased $36.6 million, or 10.2%, compared to $357.2 million in the prior year. The most significant impact on operating expenses was the increase in employee, vehicle and facility costs reflecting a full year of Agway Energy operations, offset to an extent by expense savings attributable to synergies in our northeast operations and continued expense management, particularly in light of lower operating results. Additionally, fiscal 2004 operating expenses included a $5.3 million non-cash pension charge in order to accelerate the recognition of a portion of unrecognized actuarial losses in our defined benefit pension plan as a result of an increase in the level of lump sum benefit payments made to retirees or terminated individuals during fiscal 2004 compared to prior years.

Operating expenses in fiscal 2005 increased primarily in the following areas: (i) employee compensation and benefit costs increased a net $21.1 million related to the impact of the Agway Energy operations, partially offset by lower variable compensation from lower earnings; (ii) costs to operate our fleet increased $6.6 million primarily from higher fuel costs; (iii) operating costs at our customer service centers increased $12.6 million as a result of the full year inclusion of the Agway Energy operations; and, (iv) $1.0 million higher bad debt expense associated with the high energy price environment. These increases were offset to an extent by $4.8 million lower pension costs as a result of the non-cash settlement charge included in fiscal 2004 operating expenses described above.

General and Administrative Expenses

(Dollars in thousands)			Fiscal 2005						Fiscal 2004						Decrease			Percent Decrease
General and administrative expenses				$	47,191					$	53,888				$(6,697)			(12.4%)
As a percent of total revenues					2.9	%					4.1	%

General and administrative expenses of $47.2 million for the year ended September 24, 2005 were $6.7 million, or 12.4%, lower compared to $53.9 million in fiscal 2004. The decrease was primarily attributable to a $7.7 million decline in compensation and benefit related expenses attributable to lower variable compensation in line with lower earnings, as well as the elimination of $4.2 million of costs incurred in fiscal 2004 in connection with transition services obtained on an interim basis following the Agway Acquisition and savings in other expense categories. These savings were offset somewhat by a $6.0 million increase in professional services fees associated primarily with our first-time compliance with the requirements of Section 404 of the Sarbanes-Oxley Act.

Restructuring Costs and Impairment of Goodwill.    For the year ended September 24, 2005, we recorded a restructuring charge of $2.8 million related primarily to employee termination costs incurred as a result of actions taken during fiscal 2005. Specifically, during the fourth quarter of fiscal 2005 we approved and initiated a plan of reorganization to realign our field operations. This realignment is expected to generate further efficiencies, realize operating synergies and reduce costs at the field operating level. The restructuring charge consists primarily of costs associated with severance and other employee benefits for approximately 85 positions eliminated under the plan. During fiscal 2004, we recorded a $2.9 million restructuring charge for severance and other exit costs associated with vacating duplicative facilities and contract terminations in connection with the integration of Agway Energy operations and management.

Additionally, during fiscal 2005 we recorded a non-cash charge of $0.7 million related to the impairment of goodwill associated with our HVAC segment as a result of our annual assessment of the anticipated future cash flows from that segment. During fiscal 2004, as a result of continued losses in one of our reporting units in our all other segment acquired in fiscal 1999, we recorded a non-cash charge of $3.2 million related to goodwill impairment.

40

---

Table of Contents

Depreciation and Amortization

(Dollars in thousands)			Fiscal 2005						Fiscal 2004						Increase						Percent Increase
Depreciation and amortization				$	37,762					$	36,743					$	1,019						2.8	%
As a percent of total revenues					2.3	%					2.8	%

Depreciation and amortization expense for the year ended September 24, 2005 increased $1.0 million, or 2.8%, compared to the prior year primarily as a result of a full year of depreciation and amortization on the tangible and intangible assets acquired in the Agway Acquisition. Depreciation and amortization expense in fiscal 2005 included a $0.4 million asset impairment charge associated with steps taken in the fourth quarter to realign our field operations, compared to a $1.0 million asset impairment charge in the prior year. In addition, fiscal 2005 included a non-cash charge of $0.8 million attributable to an impairment in the value of tradenames associated with our HVAC segment which were acquired in the Agway Acquisition.

Interest Expense

(Dollars in thousands)			Fiscal 2005						Fiscal 2004						Decrease						Percent Decrease
Interest expense, net				$	40,374					$	40,832					$	(458	)			(1.1%)
As a percent of total revenues					2.5	%					3.1	%

Net interest expense decreased $0.5 million, or 1.1%, to $40.4 million in fiscal 2005. The fiscal 2004 interest expense included a one-time fee of $1.9 million related to financing commitments for the Agway Acquisition. Interest expense in fiscal 2005 increased $1.4 million as a result of the net effect of a full year of interest on debt used to finance the December 2003 Agway Acquisition, offset to an extent by lower average interest rates due to our debt refinancing on March 31, 2005.

Discontinued Operations.    As part of our overall business strategy, we continually monitor and evaluate our existing operations to identify opportunities to optimize return on assets employed by selectively consolidating or divesting operations in slower growing or non-strategic markets. In line with that strategy, during fiscal 2004, we sold 24 customer service centers for net cash proceeds of $39.4 million. We recorded a gain on sale of $26.3 million during fiscal 2004. During fiscal 2005, we recorded a gain on sale of $1.0 million to reflect the finalization of certain purchase price adjustments with the buyer of the customer service centers sold in fiscal 2004. Gains on sale have been accounted for within discontinued operations in accordance with SFAS 144.

Net (Loss) Income and EBITDA.    We reported a net loss of $8.1 million for the year ended September 24, 2005 compared to net income of $54.3 million in the prior year. Adjusted EBITDA for fiscal 2005 of $107.1 million decreased $24.8 million, or 18.8%, compared to $131.9 million in the prior year. 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 recorded in the third quarter associated with our debt refinancing; (ii) a $2.8 million restructuring charge attributable primarily to severance associated with the realignment of our field operations; (iii) a $0.7 million charge attributable to impairment of goodwill associated with our HVAC segment; (iv) a $0.8 million charge included within amortization expense attributable to the impairment of other intangible assets in our HVAC segment; and (v) $0.4 million included within depreciation expense attributable to impairment of assets affected by the field realignment. In addition to the non-recurring items impacting fiscal 2005 results, the most significant negative impact on operating results was from the approximate $21.5 million impact on margin opportunities in our fuel oil business from the Ceiling Program.

By comparison, EBITDA and net income for fiscal 2004 included the net favorable impact of $8.6 million and $7.6 million, respectively, from the following significant items: (i) a $26.3 million gain from the sale of 24 customer service centers in the northern and southern central regions of the United States considered to be non-strategic; (ii) a non-cash charge of $6.3 million included within

41

---

Table of Contents

cost of products sold related to the settlement of futures contracts which were marked-to-market under purchase accounting for the Agway Acquisition; (iii) a non-cash pension settlement charge of $5.3 million related to accelerated recognition of actuarial losses in our defined benefit pension plan; (iv) a non-cash charge of $3.2 million attributable to impairment of goodwill related to a small business acquired in 1999; (v) a $2.9 million restructuring charge related to integrating certain field management and back office functions in the northeast; and (vi) a non-cash charge of $1.0 million included within depreciation expense attributable to the write-down of assets to be disposed of as a result of our efforts to integrate certain northeast operations.

EBITDA represents net income before deducting interest expense, 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 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:

			Year Ended
(Dollars in thousands)			September 24, 2005						September 25, 2004
Net (loss) income				$	(8,076	)				$	54,304
Add:
Provision for income taxes					803						3
Interest expense, net					40,374						40,832
Depreciation and amortization					37,762						36,743
EBITDA					70,863						131,882
Loss on debt extinguishment					36,242						—
Adjusted EBITDA					107,105						131,882
Add (subtract):
Provision for income taxes					(803	)					(3	)
Loss on debt extinguishment					(36,242	)					—
Interest expense, net					(40,374	)					(40,832	)
Gain on disposal of property, plant and equipment, net					(2,043	)					(715	)
Gain on sale of customer service centers					(976	)					(26,332	)
Changes in working capital and other assets and liabilities					12,338						29,065
Net cash provided by (used in)
Operating activities				$	39,005					$	93,065
Investing activities				$	(24,631	)				$	(196,557	)
Financing activities				$	(53,444	)				$	141,208

42

---

Table of Contents

Liquidity and Capital Resources

Analysis of Cash Flows

Operating Activities.    Net cash provided by operating activities for the year ended September 30, 2006 amounted to $170.3 million, an increase of $131.3 million compared to $39.0 million in the prior year. 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 collections 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.

In fiscal 2005, net cash provided by operating activities decreased $54.1 million, or 58.1%, to $39.0 million, compared to $93.1 million in fiscal 2004. The decrease was attributable to a $65.3 million increased investment in working capital in comparison to the prior year, particularly in increased accounts receivable balances as a result of the significant rise in commodity prices, coupled with $8.1 million lower income, after adjusting for non-cash items in both periods (depreciation, amortization, loss on debt extinguishment and gains on disposal of assets and customer service centers); offset to an extent by an increase in other long-term assets and liabilities of $19.3 million.

Investing Activities.    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.

Net cash used in investing activities of $24.6 million for the year ended September 24, 2005 consisted of capital expenditures of $29.3 million (including $10.7 million for maintenance expenditures and $18.6 million to support the growth of operations), offset by net proceeds of $4.7 from the sale of property, plant and equipment. Capital spending in fiscal 2005 increased $2.8 million, or 10.6%, compared to fiscal 2004 primarily as a result of our facility integration efforts in the northeast, as well as additional spending on information technology in connection with the integration of Agway Energy.

Financing Activities.    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.

Net cash used in financing activities for the year ended September 24, 2005 of $53.4 million reflects the impact of the March 31, 2005 debt refinancing which included the early retirement of $340.0 million of private placement senior notes and a related prepayment premium of $32.0 million, offset by net proceeds of $373.0 million, net of a discount, from the issuance of an additional $250.0 million of 6.875% senior notes due 2013 (bringing the total principal amount of such notes to $425.0 million) and borrowings of $125.0 million under our new Term Loan (see Summary of Long-Term Debt Obligations and Revolving Credit Lines below). In addition, we had borrowings of $26.8 million under our Revolving Credit Agreement in order to fund increased working capital needs

43

---

Table of Contents

during the heating season, offset by $4.2 million in fees associated with closing of the March 31, 2005 debt refinancing and the Third Amended and Restated Credit Agreement in October 2004. Quarterly distributions to Common Unitholders and the General Partner at a rate $0.6125 per Common Unit for each quarter of fiscal 2005 amounted to $76.6 million.

Summary of Long-Term Debt Obligations and Revolving Credit Lines

Our long-term borrowings and revolving credit lines consist of $423.3 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 (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 30, 2006. We have standby letters of credit issued under the working capital facility of the Revolving Credit Agreement in the aggregate amount of $49.3 million in support of retention levels under our self-insurance programs and certain lease obligations. Therefore, as of September 30, 2006 we had available borrowing capacity of $125.8 million under the working capital facility of the Revolving Credit Agreement. Additionally, on February 23, 2006 we executed the third amendment to the Revolving Credit Agreement which authorized our Operating Partnership 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. The third amendment provides us with greater financial flexibility for general working capital purposes during periods of peak demand, if necessary.

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, is not included in, and 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 30, 2006 and as of the end of each fiscal quarter for all periods presented in the Consolidated Financial Statements contained in this Annual Report.

Partnership Distributions

We will make distributions in an amount equal to all of our Available Cash, as defined in our Partnership Agreement, approximately 45 days after the end of each fiscal quarter to holders of

44

---

Table of Contents

record in the applicable record dates. The Board of Supervisors reviews the level of Available Cash on a quarterly basis based upon information provided by management. For the first and second quarters of fiscal 2006, we paid quarterly distributions to our Common Unitholders and the General Partner of $0.6125 per Common Unit. For the third quarter of fiscal 2006, we paid a quarterly distribution to our Common Unitholders and the General Partner of $0.6375 per Common Unit. Additionally, for the fourth quarter of fiscal 2006 we announced the eleventh increase in our quarterly distribution (since 1999) from $0.6375 to $0.6625 per Common Unit. This increase equated to $0.10 per Common Unit on an annualized basis to $2.65 per Common Unit. The quarterly distribution at this increased level was paid in respect of the fourth quarter of fiscal 2006 on November 14, 2006 to Common Unitholders of record on November 7, 2006.

Prior to the completion of the GP Exchange Transaction, as described above, our General Partner held IDRs and other economic interests in the Partnership and the Operating Partnership. With regard to the first $0.55 of the Common Unit distribution, 98.26% of the Available Cash was distributed to the Common Unitholders and 1.74% was distributed to the General Partner. With regard to the balance of the Common Unit distributions paid, approximately 85% of the Available Cash was distributed to the Common Unitholders and approximately 15% was distributed to the General Partner. With the completion of the GP Exchange Transaction, the IDRs have been cancelled and the General Partner is no longer entitled to receive any cash distributions in respect of its general partner interests; accordingly, 100% of all cash distributions, beginning with the quarterly distribution paid on November 14, 2006, will be paid to holders of Common Units (including the current and former members of management who owned the General Partner).

Pension Plan Assets and Obligations

While our pension asset portfolio has experienced significantly improved asset returns over the past three fiscal years, the funded status of our defined benefit pension plan continues to be affected by the negative impact of the low interest rate environment on the actuarial value of the projected benefit obligations, as well as the cumulative impact of prior losses particularly during fiscal 2002 and fiscal 2001. The projected benefit obligation as of September 30, 2006 exceeded the market value of pension plan assets by $31.1 million, a decrease of $9.1 million compared to the $40.2 million underfunded position at the end of the prior year.

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 2006, 2005 or 2004. However, in an effort to proactively address our funded status, we elected to make voluntary contributions to our defined benefit pension plan of $10.0 million and $15.1 million during fiscal 2006 and fiscal 2004, respectively. These voluntary contributions, coupled with improved asset returns in our pension asset portfolio during fiscal 2006, fiscal 2005 and fiscal 2004 have contributed to the improvement in the funded status of our defined benefit pension plan.

During fiscal 2006, lump sum benefit payments of $11.5 million exceeded the interest cost component 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 $4.4 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 $5.3 million was recorded in fiscal 2004 as a result of the level of lump sum benefit payments. As of September 30, 2006, the cumulative reduction to partners’ capital decreased to $66.8 million, compared to $75.7 million at the end of fiscal 2005, primarily as a result of continued strength in our asset portfolio returns, offset to an extent by lower benchmark interest rates. The cumulative reduction to partners’ capital is attributable to the level of unrealized losses experienced on our

45

---

Table of Contents

pension assets over the past several years and represents non-cash charges to our partners’ capital with no impact on the results of operations for the year ended September 30, 2006. Additional pension settlement charges may be required in future periods depending on the level of lump sum benefit payments.

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. For purposes of computing the actuarial valuation of projected benefit obligations, we increased the discount rate assumption from 5.25% as of September 24, 2005 to 5.50% as of September 30, 2006 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 2006, 2005 and 2004 we assumed increased long-term rates of return on plan assets of 8.00%, 7.50% and 7.75%, respectively, based on the investment mix of our pension asset portfolio, historical asset performance and expectations for future performance. There are currently no minimum funding requirements projected for fiscal 2007 and, based on information provided by our actuaries, we do not project any minimum funding requirements until fiscal 2009.

A one-percentage point increase or decrease in the weighted-average expected long-term rate of return on plan assets and the weighted-average discount rate would have had the following effect on the fiscal 2006 pension expense:

			Increase/(Decrease) in Pension Expense
			1% Increase						1% Decrease
Weighted-average expected long-term rate of return on plan assets				$	(1,292	)				$	1,288
Weighted-average discount rate					(542	)					128

We also provide postretirement health care and life insurance benefits for certain retired employees. Partnership employees who were hired prior to July 1993 and retired prior to March 1998 are eligible for such benefits if they reached a specified retirement age while working for the Partnership. Effective January 1, 2000, we terminated our postretirement benefit plan for all eligible employees retiring after March 1, 1998. All active and eligible employees who were to receive benefits under the postretirement plan subsequent to March 1, 1998 were provided a settlement by increasing their accumulated benefits under the defined benefit pension plan noted above. Our postretirement health care and life insurance benefit plans are unfunded.

Long-Term Debt Obligations and Operating Lease Obligations

Contractual Obligations

Long-term debt obligations and future minimum rental commitments under noncancelable operating lease agreements as of September 30, 2006 are due as follows:

(Dollars in thousands)			Fiscal 2007						Fiscal 2008						Fiscal 2009						Fiscal 2010						Fiscal 2011 and thereafter						Total
Short-term and long-term debt				$	—					$	—					$	—					$	125,000					$	423,304					$	548,304
Future interest payments					35,603						37,731						37,731						35,603						102,266						248,934
Operating leases					17,280						11,450						7,865						5,258						4,996						46,849
Total debt obligations, cash interest and lease commitments				$	52,883					$	49,181					$	45,596					$	165,861					$	530,566					$	844,087

Additionally, we have standby letters of credit in the aggregate amount of $49.3 million, in support of retention levels under our casualty insurance programs and certain lease obligations, which expire periodically through April 15, 2007.

46

---

Table of Contents

Off-Balance Sheet Arrangements

Operating Leases

We lease certain property, plant and equipment for various periods under noncancelable operating leases, including approximately 67% of our vehicle fleet, approximately 24% of our customer service centers and portions of our information systems equipment. Rental expense under operating leases was $27.2 million, $28.6 million and $27.3 million for fiscal 2006, 2005 and 2004, respectively. Future minimum rental commitments under noncancelable operating lease agreements as of September 30, 2006 are presented in the table above.

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 2012. Upon completion of the lease period, we guarantee that the fair value of the equipment will equal or exceed the guaranteed amount, or we will pay the lessor the difference. Although the fair value of equipment at the end of its lease term has historically exceeded the guaranteed amounts, the maximum potential amount of aggregate future payments we could be required to make under these leasing arrangements, assuming the equipment is deemed worthless at the end of the lease term, is approximately $17.2 million. Of this amount, the fair value of residual value guarantees for operating leases entered into after December 31, 2002 is reflected in other liabilities, with a corresponding amount included within other assets in the accompanying consolidated balance sheet totaling $8.3 million and $6.3 million as of September 30, 2006 and September 24, 2005, respectively.

Recently Issued Accounting Standards

In September 2006, the Financial Accounting Standards Board (‘‘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. SFAS 157 will be effective September 28, 2008, the beginning of our fiscal 2009. 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.

Also in September 2006, the FASB issued SFAS No. 158, ‘‘Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – An Amendment of FASB Statements No. 87, 88, 103 and 132R’’ (‘‘SFAS 158’’). SFAS 158 requires companies to recognize the funded status of pension and other postretirement benefit plans on sponsoring employers’ balance sheets and to recognize changes in the funded status in the year the changes occur. It also requires the measurement date of plan assets and obligations to occur at the end of the employers’ fiscal year. SFAS 158 is effective as of the end of our fiscal 2007. Based on our funded status and the consolidated balance sheet recognition as of September 30, 2006 (as disclosed in Note 12 to the Consolidated Financial Statements included in this Annual Report), adoption of SFAS 158 is not expected to have a significant impact on our consolidated financial position since the accrued pension liability already reflects the funded status of the defined benefit pension plan. Additionally, there would have been no impact to our consolidated statements of operations or cash flows for the year ended September 30, 2006. The actual impact from the adoption of SFAS 158 on the September 29, 2007 consolidated financial statements will differ due to changes in economic assumptions such as discount rates, measurement of fair values of plan assets and other possible changes in actuarial assumptions that may occur in connection with the upcoming fiscal 2007 measurement date.

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

47

---

Table of Contents

statements. FIN 48 is effective for fiscal years beginning after December 15, 2006 which is the beginning of our fiscal 2008. 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.

ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

As of September 30, 2006, we were a party to exchange-traded futures and option contracts, forward contracts and in certain instances, over-the-counter options (collectively ‘‘derivative instruments’’) to manage the price risk associated with future purchases of the commodities used in our operations, principally propane and fuel oil. Futures and forward contracts require their holder to buy or sell propane or fuel oil at a fixed price at fixed future dates. An option contract allows, but does not require, its holder to buy or sell propane or fuel oil at a specified price during a specified time period; the writer of an option contract must fulfill the obligation of the option contract should the holder choose to exercise the option. At expiration, the contracts are settled by the delivery 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. The contracts are entered into in anticipation of market movements and to manage and hedge exposure to fluctuating prices of propane and fuel oil, as well as to help ensure the availability of product during periods of high demand.

Market Risk

We are subject to commodity price risk to the extent that propane or fuel oil market prices deviate from fixed contract settlement amounts. Futures traded with brokers 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 30, 2006, the fair value of the interest rate swap was $1.2 million representing an unrealized gain and was included within other assets.

Derivative Instruments and Hedging Activities

We account for derivative instruments in accordance with the provisions of SFAS 133. All derivative instruments are reported on the balance sheet, within other current assets or other current liabilities, at their fair values. Fair values for forward contracts and futures are derived from quoted market prices for similar instruments traded on the NYMEX. Fair values for option contracts are

48

---

Table of Contents

derived using generally accepted published option pricing models. 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 hedges are recognized in cost of products sold immediately.

Changes in the fair value of derivative instruments that are not designated as hedges are recorded in current period earnings within cost of products sold. A portion of our option contracts are not classified as hedges and, as such, changes in the fair value of these derivative instruments are recognized within cost of products sold as they occur. The value of certain option contracts that do qualify as hedges and are designated as cash flow hedges under SFAS 133 have two components of value: time value and intrinsic value. The intrinsic value is the value by which the option is in the money (i.e., the amount by which the value of the commodity exceeds the exercise or ‘‘strike’’ price of the option). The remaining amount of option value is attributable to time value. We do not include the time value of option contracts in our assessment of hedge effectiveness and, therefore, record changes in the time value component of the options currently in earnings.

At September 30, 2006, the fair value of derivative instruments described above resulted in derivative assets (unrealized gains) of $9.6 million included within prepaid expenses and other current assets and derivative liabilities (unrealized losses) of $2.5 million included within other current liabilities. Cost of products sold included unrealized (non-cash) gains in the amount of $14.5 million for the year ended September 30, 2006 compared to unrealized (non-cash) losses of $2.5 million for the year ended September 24, 2005, attributable to the change in fair value of derivative instruments not designated as cash flow hedges. As of September 30, 2006, unrealized losses on derivative instruments designated as cash flow hedges in the amount of $1.9 million were included in OCI and are expected to be recognized in earnings during the next 12 months as the hedged transactions occur.

Sensitivity Analysis

In an effort to estimate our exposure to unfavorable market price changes in propane or fuel oil related to our open positions under derivative instruments, we developed a model that incorporates the following data and assumptions:

	A.	The actual fixed contract price of open positions as of September 30, 2006 for each of the future periods.

	B.	The estimated future market prices for futures and forward contracts as of September 30, 2006 as derived from the NYMEX for traded propane or fuel oil futures for each of the future periods.

	C.	The market prices determined in B. above were adjusted adversely by a hypothetical 10% change in the future periods and compared to the fixed contract settlement amounts in A. above to project the potential negative impact on earnings that would be recognized for the respective scenario.

Based on the sensitivity analysis described above, the hypothetical 10% adverse change in market prices for each of the future months for which a future, forward and/or option contract exists indicates either future losses or a reduction in potential future gains of $3.2 million as of September 30, 2006. 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 30, 2006 at Mont Belvieu, Texas (a major storage point) was $0.9475 per gallon as compared to $1.1638 per gallon on September 24, 2005.

49

---

Table of Contents

The average posted price of fuel oil on September 30, 2006 at Linden, New Jersey was $1.685 per gallon as compared to $1.949 per gallon on September 24, 2005. The average posted price of propane on December 7, 2006 at Mont Belvieu, Texas was $0.9938 per gallon, representing a 5.0% decrease since the end of Fiscal 2006. The average posted price of fuel oil on December 7, 2006 at Linden, New Jersey was $1.719 per gallon, representing a 2.0% increase since the end of Fiscal 2006.

As of September 30, 2006, our open position portfolio reflected a net short position (sell contracts) aggregating $25.5 million.

50

---

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).

			First Quarter						Second Quarter						Third Quarter						Fourth Quarter (a)						Total Year (a)
Fiscal 2006
Revenues				$	487,463					$	590,943					$	303,998					$	279,236					$	1,661,640
Income (loss) before interest expense and provision for income taxes (b)					48,932						95,051						(666	)					(11,133	)					132,184
Net income (loss) (b)					38,215						84,029						(10,473	)					(21,031	)					90,740
Net income (loss) per common unit – basic (d)					1.15						2.44						(0.33	)					(0.66	)					2.84
Net income (loss) per common unit – diluted (d)					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 (e)				$	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
Fiscal 2005
Revenues				$	424,046					$	587,369					$	327,180					$	281,639					$	1,620,234
Income (loss) before interest expense, loss on debt extinguishment and provision for income taxes (b)					34,853						75,070						(13,589	)					(27,967	)					68,367
Income (loss) from continuing operations (b)					24,901						64,481						(59,912	)					(38,522	)					(9,052	)
Discontinued operations:
Gain on sale of customer service centers (c)					—						976						—						—						976
Net income (loss) (b)					24,901						65,457						(59,912	)					(38,522	)					(8,076	)
Income (loss) from continuing operations per common unit – basic (d)					0.77						1.89						(1.92	)					(1.23	)					(0.29	)
Net income (loss) per common unit – basic (d)					0.77						1.91						(1.92	)					(1.23	)					(0.26	)
Net income (loss) per common unit – diluted (d)					0.77						1.90						(1.92	)					(1.23	)					(0.26	)
Cash (used in) provided by
Operating activities					(29,627	)					7,531						44,383						16,718						39,005
Investing activities					(7,909	)					(5,035	)					(6,182	)					(5,505	)					(24,631	)
Financing activities					(96	)					(1,443	)					(43,895	)					(8,010	)					(53,444	)
EBITDA and Adjusted EBITDA (e)				$	43,972					$	85,244					$	(4,393	)				$	(17,718	)				$	107,105
Retail gallons sold
Propane					141,780						199,124						98,008						77,128						516,040
Fuel oil and refined fuels					65,906						92,886						48,468						37,276						244,536

(a)	Fiscal 2006 includes 53 weeks of operations compared to 52 weeks in fiscal 2005. The fourth quarter of fiscal 2006 includes 14 weeks of operations compared to 13 weeks in the fourth quarter of fiscal 2005.

51

---

Table of Contents

(b)	These amounts include, in addition to the gain on sale of customer service centers, gains from the disposal of property, plant and equipment of $1.0 million for fiscal 2006 and $2.0 million for fiscal 2005.

(c)	Gain on sale of customer service centers recorded in the second quarter of fiscal 2005 reflects a $1.0 million finalization of certain purchase price adjustments with the buyer of the customer service centers sold in fiscal 2004, accounted for within discontinued operations pursuant to SFAS 144.

(d)

Computations of earnings per Common Unit are performed in accordance with EITF 03-6 which requires, among other things, the use of the two-class method of computing earnings per unit when participating securities exist. The two-class method is an earnings allocation formula that computes earnings per unit for each class of Common Unit and participating security according to distributions declared and participation rights in undistributed earnings, as if all of the earnings were distributed to the limited partners and the general partner (inclusive of the IDRs which are considered participating securities for purposes of the application of EITF 03-6). Income is allocated to the 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. Following the GP Exchange Transaction consummated on October 19, 2006, the two-class method of computing income per Common Unit under EITF 03-6 will no longer be 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 and 2005, nor did it have any impact on the computation of net loss per Common Unit for the year ended September 24, 2005. Net income and income from continuing operations per Common Unit presented in this table for the first and second quarters of fiscal 2006 and 2005, 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, after deducting our General Partner’s interest, by the weighted average number of outstanding Common Units and time vested restricted units granted under our 2000 Restricted Unit Plan.

(e)

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 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 (amounts in thousands):

52

---

Table of Contents

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					8,211						8,898						7,756						8,286						33,151
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	)
(Gain) loss on disposal of property, plant and equipment, net					(44	)					(577	)					(568	)					189						(1,000	)
Changes in working capital and other assets and liabilities					(55,314	)					(28,582	)					69,333						61,993						47,430
Net cash provided by (used in)
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	)

Fiscal 2005			First Quarter						Second Quarter						Third Quarter						Fourth Quarter						Total Year
Net income (loss)				$	24,901					$	65,457					$	(59,912	)				$	(38,522	)				$	(8,076	)
Add:
Provision for income taxes					89						109						138						467						803
Interest expense, net					9,863						10,480						9,943						10,088						40,374
Depreciation and amortization					9,119						9,198						9,196						10,249						37,762
EBITDA					43,972						85,244						(40,635	)					(17,718	)					70,863
Loss on debt extinguishment					—						—						36,242						—						36,242
Adjusted EBITDA					43,972						85,244						(4,393	)					(17,718	)					107,105
Add (subtract):
Provision for income taxes					(89	)					(109	)					(138	)					(467	)					(803	)
Loss on debt extinguishment					—						—						(36,242	)					—						(36,242	)
Interest expense, net					(9,863	)					(10,480	)					(9,943	)					(10,088	)					(40,374	)
Gain on disposal of property, plant and equipment, net					(207	)					(860	)					(821	)					(155	)					(2,043	)
Gain on sale of customer service centers					—						(976	)					—						—						(976	)
Changes in working capital and other assets and liabilities					(63,440	)					(65,288	)					95,920						45,146						12,338
Net cash provided by (used in)
Operating activities				$	(29,627	)				$	7,531					$	44,383					$	16,718					$	39,005
Investing activities				$	(7,909	)				$	(5,035	)				$	(6,182	)				$	(5,505	)				$	(24,631	)
Financing activities				$	(96	)				$	(1,443	)				$	(43,895	)				$	(8,010	)				$	(53,444	)

53

---

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.

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.

On December 6, 2006, 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 30, 2006. 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 30, 2006.

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 30, 2006, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. Management’s Report on Internal Control over Financial Reporting is included below.

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING. Management 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 30, 2006. 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 30, 2006, the Partnership’s internal control over financial reporting was effective.

54

---

Table of Contents

Management’s assessment of the effectiveness of the Partnership’s internal control over financial reporting as of September 30, 2006 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.

55

---

Table of Contents

PART III

ITEM 10.	DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Partnership Management

Our Partnership Agreement provides that all management powers over our business and affairs are exclusively vested in our Board of Supervisors and, subject to the direction of the Board of Supervisors, our officers. No Unitholder has any management power over our business and affairs or actual or apparent authority to enter into contracts on behalf of or otherwise to bind us. There are currently five 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 (see Item 4 of this Annual Report), 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 2009), at which meeting all Supervisors will be elected by the Common Unitholders.

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

56

---

Table of Contents

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 December 7, 2006. Officers are appointed by the Board of Supervisors for one-year terms and Supervisors are elected by the Unitholders for three-year terms.

Name			Age			Position With the Partnership
Mark A. Alexander			48			Chief Executive Officer; Member of the Board of Supervisors (appointed by the General Partner)
Michael J. Dunn, Jr.			57			President; Member of the Board of Supervisors (appointed by the General Partner)
Robert M. Plante			58			Vice President and Chief Financial Officer
Dennis W. Trautman			47			Chief Operating Officer
Jeffrey S. Jolly			54			Vice President and Chief Information Officer
Michael M. Keating			53			Vice President – Human Resources and Administration
Paul Abel			53			General Counsel and Secretary
Douglas T. Brinkworth			44			Vice President – Supply
A. Davin D’Ambrosio			42			Treasurer
Michael A. Stivala			37			Controller and Chief Accounting Officer
John Hoyt Stookey			76			Member of the Board of Supervisors (Chairman)
Harold R. Logan, Jr.			61			Member of the Board of Supervisors (Chairman of the Audit Committee)
Dudley C. Mecum			71			Member of the Board of Supervisors

Mr. Alexander has served as Chief Executive Officer and as a Supervisor (appointed by the General Partner) 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. 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 (appointed by the General Partner) 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. Plante has served as a Vice President since October 1999 and became Chief Financial Officer in November 2003. He was Vice President – Finance from March 2001 until November 2003 and Treasurer from March 1996 through October 2002. Mr. Plante held various financial and managerial positions with predecessors of the Partnership from 1977 until 1996.

Mr. Trautman became Chief Operating Officer in May 2005. He joined the Partnership in December 2003 as Managing Director, Northeast Operations, upon the Partnership’s acquisition of substantially all the assets and operations of Agway Energy. For the balance of the prior five years, Mr. Trautman served as Chief Operating Officer of Agway Energy, then a leading regional marketer of propane, fuel oil, gasoline and diesel fuel.

Mr. Jolly has served as Vice President and Chief Information Officer since May 1999. He was Vice President – Information Services from July 1997 until May 1999. Before joining the Partnership, Mr. Jolly was Vice President – Information Systems at The Wood Company, a food services company.

Mr. Keating has served as Vice President – Human Resources and Administration since July 1996. He previously held senior human resource positions at Hanson Industries and Quantum Chemical Corporation (‘‘Quantum’’), a predecessor of the Partnership.

57

---

Table of Contents

Mr. Abel has served as General Counsel and Secretary since June 2006. 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. 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. D’Ambrosio became Treasurer in November 2002. He served as Assistant Treasurer from October 2000 to November 2002 and as Director of Treasury Services from January 1998 to October 2000. Mr. D’Ambrosio joined the Partnership in May 1996 after ten years in the commercial banking industry.

Mr. Stivala has served as Controller and Chief Accounting Officer since May 2005. Prior to that he was 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. Stookey has served as a Supervisor and Chairman of the Board of Supervisors since March 1996. From 1986 until September 1993, he was the Chairman, President and Chief Executive Officer of Quantum. 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).

Mr. Logan has served as a Supervisor since March 1996. 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 The Houston Exploration Company, Graphic Packaging, Inc. and Hart Energy Publishing LLP.

Mr. Mecum has served as a Supervisor since June 1996. He has been a managing director of Capricorn Holdings, LLC (a sponsor of and investor in leveraged buyouts) since June 1997. Mr. Mecum was a partner of G.L. Ohrstrom & Co. (a sponsor of and investor in leveraged buyouts) from 1989 to June 1996. Mr. Mecum is also a Director of CitiGroup.

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 2006.

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

58

---

Table of Contents

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

We have adopted a Compensation Committee Charter in accordance with the NYSE corporate governance listing standards in effect as of the date of this Annual Report. 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 2006 to the NYSE without qualification.

59

---

Table of Contents

ITEM 11.	EXECUTIVE COMPENSATION

Summary Compensation Table

The following table sets forth a summary of all compensation awarded or paid to or earned by our chief executive officer and our four other most highly compensated executive officers for services rendered to us during each of the last three fiscal years.

									Annual Compensation												Restricted Unit Awards ($)2						LTIP Payout						All Other Compensation3
Name and Principal Position			Year						Salary						Bonus1
Mark A. Alexander					2006					$	450,000					$	490,500					$	—					$	415,513					$	35,998
Chief Executive Officer					2005						450,000						—						—						267,526						36,520
					2004						450,000						201,150						—						—						170,625
Michael J. Dunn, Jr.					2006						375,000						408,750						—						262,217						29,041
President					2005						300,000						—						—						59,142						28,933
					2004						280,000						280,000						—						44,104						112,738
Dennis W. Trautman					2006						300,000						277,950						502,413						62,085						39,030
Chief Operating Officer					2005						225,000						—						—						—						18,808
					2004						225,000						300,000						751,444						—						74,733
Robert M. Plante					2006						235,000						204,920						—						159,217						27,696
Vice President and Chief					2005						225,000						—						—						—						27,185
Financial Officer					2004						200,000						150,000						—						—						68,392
Jeffrey S. Jolly					2006						204,000						144,534						—						105,013						28,508
Vice President and Chief					2005						200,000						—						—						22,442						27,688
Information Officer					2004						185,000						120,250						—						16,716						63,786

1	Bonuses are reported for the year earned, regardless of the year paid.

2

On December 24, 2003 and October 1, 2005, Mr. Trautman was awarded grants of 23,810 and 17,388 Restricted Units, respectively. The vesting of these Restricted Unit grants accord with the vesting schedule set forth in Note 10 to the Consolidated Financial Statements included in this Annual Report. However, earlier vesting may occur due to disability or retirement, a change in control of the Partnership, termination of employment without cause, or by special action of the Compensation Committee. Upon vesting, the recipient of an award will receive Common Units. Distributions are not paid on Restricted Units until vested and Common Units are issued. At the end of the fiscal year, based on the September 29, 2006 closing price of $33.76, Mr. Trautman’s Restricted Unit grants were valued at $1,390,844.

3

As explained in Note 12 to the Consolidated Financial Statements included in this Annual Report, the Partnership maintains a 401(k) Plan (‘‘Retirement Savings and Investment Plan’’) for its employees to which the Partnership makes contributions and incurs costs that are a percent of the participating employees’ compensation. The Partnership maintains a cash balance pension plan for employees who are eligible for participation in the plan (the ‘‘Pension Plan’’). Although the Partnership makes no further contributions to the Pension Plan, the amounts reported in the column identified as ‘‘All Other Compensation’’ represent each participant’s pro-rata share of the administrative fees incurred to maintain the Pension Plan. The Partnership provides certain senior executives with an automobile at the Partnership’s expense. The Partnership incurs costs for the provision of health, disability, and basic life insurance to its employees. In addition to this insurance, the Partnership also provides Mr. Alexander with supplemental disability as well as supplemental life insurance of which Mr. Alexander’s immediate family members are the designated beneficiaries. All Other Compensation includes the following for fiscal 2006 for Mr. Alexander: $1,260 under the Retirement Savings and Investment Plan; $1,500 in

60

---

Table of Contents

administrative fees under the Pension Plan; $9,275 related to a vehicle; and $23,963 for insurance. For Mr. Dunn, this amount includes the following: $1,260 under the Retirement Savings and Investment Plan; $1,500 in administrative fees under the Pension Plan; $9,685 related to a vehicle; and $16,596 for insurance. For Mr. Trautman, this amount includes the following: $981 under the Retirement Savings and Investment Plan; $1,111 related to a vehicle; $11,738 for insurance; and $25,200 for a residence maintained for Mr. Trautman by the Partnership. For Mr. Plante, this amount includes the following: $1,260 under the Retirement Savings and Investment Plan; $1,500 in administrative fees under the Pension Plan; $10,045 related to a vehicle; and $14,891 for insurance. For Mr. Jolly, this amount includes the following: $1,204 under the Retirement Savings and Investment Plan; $1,500 in administrative fees under the Pension Plan; $11,191 related to a vehicle; and $14,613 for insurance.

Retirement Benefits

The following table sets forth the annual benefits upon retirement at age 65, without regard to statutory maximums for various combinations of final average earnings and lengths of service which may be payable to Messrs. Alexander, Dunn, Plante and Jolly under the Pension Plan for Eligible Employees of the Operating Partnership and its Subsidiaries and/or the Suburban Propane Company Supplemental Executive Retirement Plan, both of which were frozen on December 31, 2002. Each such person was credited for service earned until the date on which the plan was frozen. Messrs. Alexander and Dunn have 7 years and 6 years, respectively, under both plans. Messrs. Plante and Jolly have 26 years and 6 years, respectively, under the Pension Plan. For vesting purposes, however, Mr. Alexander has 22 years combined service with the Partnership and his prior service with Hanson Industries and Messrs. Dunn, Plante and Jolly have 9 years, 29 years and 9 years, respectively. Mr. Trautman has no benefits under either plan.

Pension Plan
Annual Benefit for Years of Credited Service Shown^1,2,3,4,5

Average Earnings					5 Yrs.						10 Yrs.						15 Yrs.						20 Yrs.						25 Yrs.						30 Yrs.						35 Yrs.
	$100,000					$	7,888					$	15,775					$	23,663					$	31,551					$	39,438					$	47,326					$	55,214
	200,000						16,638						33,275						49,913						66,551						83,188						99,826						116,464
	300,000						25,388						50,775						76,163						101,551						126,938						152,326						177,714
	400,000						34,138						68,275						102,413						136,551						170,688						204,826						238,964
	500,000						42,888						85,775						128,663						171,551						214,438						257,326						300,214

1	The Pension Plan’s definitions of earnings consist of base pay only.

2

Annual Benefits are computed on the basis of straight life annuity amounts. The pension benefit is calculated as the sum of (a) plus (b) multiplied by (c) where (a) is that portion of final average earnings up to 125% of social security Covered Compensation times 1.4% and (b) is that portion of final average earnings in excess of 125% of social security Covered Compensation times 1.75% and (c) is credited service up to a maximum of 35 years.

3

Effective January 1, 1998, the Pension Plan was amended to a cash balance benefit formula for current and future plan participants. Initial account balances were established based upon the actuarial equivalent value of the accrued benefit under the prior plan as of December 31, 1997. Annual interest credits and service based credits were credited to the accounts until December 31, 2002. The Pension Plan was frozen to new participants effective January 1, 2000, and effective January 1, 2003 all future service based credits were discontinued. Interest credits continue to be applied based upon the five-year U.S. Treasury bond rate in effect during the preceding November, plus one percent. Pension Plan participants as of December 31, 1997 are entitled to receive the greater of the cash balance benefit and the prior plan benefit through the year 2002.

61

---

Table of Contents

4

In addition, a supplemental cash balance account was established equal to the value of certain benefits related to retiree medical and vacation benefits. An initial account value was determined for those active employees who were eligible for retiree medical coverage as of April 1, 1998 equal to $415 multiplied by years of benefit service (maximum of 35 years). Effective January 1, 2003, only interest is credited to this account.

5	Effective January 1, 2003 the Annual Benefits accrued by Messrs. Alexander and Dunn pursuant to the Supplemental Executive Retirement Plan (in excess of the statutory limitations governing the Pension Plan) were, in the aggregate, approximately $85,000.

Supplemental Executive Retirement Plan

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 certain executive officers with a level of retirement income from us, without regard to statutory maximums, including the IRS limitation for defined benefit plans. Effective January 1, 1998, the Pension Plan was amended and restated as a cash balance plan. In light of the conversion of the Pension Plan to a cash balance formula, 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 described under the Retirement Benefits section above, applied to the amount of annual compensation that exceeds the IRS statutory maximums for defined benefit plans which was $200,000 in 2002. Messrs. Alexander and Dunn are the only executive officers who currently participate in the SERP.

Effective January 1, 2003, the SERP was discontinued with a frozen benefit determined for Messrs. Alexander and Dunn. Provided that the SERP requirements are met, Mr. Alexander will receive a monthly benefit of $6,737 and Mr. Dunn will receive a monthly benefit of $373. In the event of a change of control involving the Partnership, the SERP will terminate effective on the close of business 30 days following the change of control. Each participant will be deemed retired and will have his benefit determined as of the date the plan is terminated with payment of the benefit no later than 90 days after the change in control. Each participant will receive a lump sum payment equivalent to the present value of each participant’s benefit payable under the plan utilizing the lesser of the prime rate of interest as published in the Wall Street Journal as of the date of the change of control or one percent, whichever is less, as the discount rate to determine the present value of the accrued benefit.

Long-Term Incentive Plan

Effective October 1, 1997, we adopted a non-qualified, unfunded long-term incentive plan for officers and key employees (‘‘LTIP-1’’). LTIP-1 awards are based on a percentage of base pay and are subject to the achievement of certain performance criteria, including our ability to earn sufficient funds and make cash distributions on our Common Units with respect to each fiscal year. Awards vest over a five-year period with one-third vesting at the beginning of each of years three, four, and five following the award date. Effective September 30, 2004, LTIP-1 was discontinued with the effect that no new awards will be made after that date, but all award grants prior thereto will continue to vest and be payable in accordance with their terms. Prior to the enactment of Internal Revenue Code (‘‘IRC’’) Section 409A, payouts, if any, of awards made prior to September 30, 2004 under LTIP-1 were expected to be made annually through the end of fiscal year 2011. In the event of a change of control of the Partnership, all earned unvested awards under LTIP-1 shall be deemed vested and all outstanding awards shall be paid to participants within 30 days following the change of control.

On November 2, 2005, the Board of Supervisors approved amendments to LTIP-1 for the purpose of IRC Section 409A compliance. The principal amendments provided (i) that all previously vested amounts under LTIP-1 as of the date of the amendment were distributed to participants by December 31, 2005; (ii) that all future vested amounts will be distributed to plan participants within 30 days after such amounts become vested; and (iii) that deferrals of awards under LTIP-1 are no longer permitted after December 31, 2004. The purpose of the amendments is to ensure that LTIP-1 operates in compliance with IRC Section 409A.

62

---

Table of Contents

Effective October 1, 2002, we adopted a new non-qualified, unfunded long-term incentive plan for officers and key employees (‘‘LTIP-2’’). The new plan measures our performance on the basis of total return to Unitholders (‘‘TRU’’) and compares that to a predetermined peer group, primarily comprised of other Master Limited Partnerships, approved by our Compensation Committee. Awards are granted in respect of and payouts, if any, are earned at the end of a three-year performance period. Depending on the quartile ranking within which our performance falls for the applicable performance period relative to the peer group, LTIP-2 participants will receive a payout equal to the product of (a) a factor based on the participant’s salary and bonus at the beginning of the performance period; and (b) an amount determined pursuant to the formula used to measure TRU, 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 first performance period for which awards under LTIP-2 were granted in fiscal 2003 were available to be earned based on performance measured during the period from October 1, 2002 through September 30, 2005. No awards were earned or paid for that performance period since our performance fell within the lowest quartile. The second performance period for which awards under LTIP-2 were granted in fiscal 2004 were available to be earned based on performance measured during the period from September 28, 2003 through September 30, 2006. During this period, our performance fell within the second lowest quartile and, as a result, participants earned awards totaling $1,215,335 which were paid in November 2006. The third performance period for which awards under LTIP-2 were granted in fiscal 2005 are available to be earned based on performance measured during the period starting September 26, 2004 and ending September 29, 2007 (the end of fiscal 2007). Upon a change of control of the Partnership, all outstanding awards under LTIP-2 shall be determined as if our performance fell within the top quartile and shall be paid to participants within 30 days following the change of control.

On September 25, 2005 (the beginning of fiscal 2006), awards under LTIP-2 were granted and are available to be earned based on performance measured during the period starting September 25, 2006 and ending September 27, 2008. Because the formula used to determine TRU incorporates market value at the end of the performance period and the sum of distributions paid to Unitholders during the performance period, both of which are variables that cannot be predicted prior to the end of the performance period (September 30, 2008 in the case of the fiscal 2006 grant), target award amounts are not determinable in advance. However, the table below sets forth hypothetical payments of the awards granted during fiscal 2006 to our Chief Executive Officer and four other most highly compensated officers under LTIP-2 as if the fiscal 2006 award grants had vested over a three-year measurement period ending at the conclusion of our 2006 fiscal year and our ranking fell within the second highest quartile.

Name			Performance Period for Fiscal 2006 Grant			Hypothetical Award Earned
Mark A. Alexander			September 2005 – September 2008				$	88,729
Michael J. Dunn, Jr.			September 2005 – September 2008				$	128,174
Dennis W. Trautman			September 2005 – September 2008				$	87,151
Robert M. Plante			September 2005 – September 2008				$	64,251
Jeffrey S. Jolly			September 2005 – September 2008				$	45,328

On October 17, 2006, the Board of Supervisors approved an amendment of LTIP-2 for the purpose of IRC Section 409A compliance. This amendment provided for the delay in the distribution of any awards under LTIP-2 upon retirement of a participant until six months after the date of separation of service, to the extent that such distribution is treated as deferred compensation under IRC Section 409A. The purpose of the amendment is to ensure that LTIP-2 operates in compliance with IRC Section 409A.

Restricted Unit Plan

A description of the Restricted Unit Plan is included in Note 10 to the Consolidated Financial Statements included in this Annual Report.

63

---

Table of Contents

Employment Agreement with the Chief Executive Officer

We entered into an employment agreement (the ‘‘Employment Agreement’’) with Mr. Alexander, which became effective March 5, 1996 and was amended October 23, 1997, April 14, 1999 and November 2, 2005.

Mr. Alexander’s Employment Agreement had an initial term of three years, and automatically renews for successive one-year periods, unless earlier terminated by us or by Mr. Alexander or otherwise terminated in accordance with the Employment Agreement. The Employment Agreement provides for an annual base salary of $450,000 as of September 30, 2006 and provides for Mr. Alexander to earn a bonus up to 100% of annual base salary (the ‘‘Maximum Annual Bonus’’) for services rendered based upon certain performance criteria. Under the Partnership Agreement, the Compensation Committee has the authority to grant Mr. Alexander a bonus in excess of the Maximum Annual Bonus, consistent with the percentage bonuses granted to our other senior executives, for fiscal years in which the Partnership’s performance exceeds the applicable criteria. The Compensation Committee exercised this authority in connection with Mr. Alexander’s bonus for fiscal 2006 (see ‘‘Summary Compensation Table’’ above). The Employment Agreement also provides for the opportunity to participate in benefit plans made available to our other senior executives and senior managers. We also provide Mr. Alexander with term life insurance with a face amount equal to three times his annual base salary, of which Mr. Alexander’s immediate family members are the designated beneficiaries.

If a ‘‘change of control’’ (as defined in the next paragraph) 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 Employment Agreement) or if Mr. Alexander resigns with ‘‘good reason’’ (as defined in the Employment Agreement) or terminates his employment during the six month period commencing on the six month anniversary and ending on the twelve month anniversary of such change of control, then Mr. Alexander will be entitled to (i) a lump sum severance payment equal to three times the sum of his annual base salary in effect as of the date of termination plus the Maximum Annual Bonus, and (ii) medical benefits for three years from the date of such termination. The Employment Agreement provides that if any payment received by Mr. Alexander is subject to the 20% federal excise tax under Section 4999 and, pursuant to an amendment approved by the Board of Supervisors on November 2, 2005, Section 409A of the IRC, the payment will be increased to permit Mr. Alexander to retain a net amount on an after-tax basis equal to what he would have received had the excise tax not been payable.

For the purposes of the Employment Agreement, ‘‘change of control’’ means the occurrence during the employment term of: (i) an acquisition of our Common Units or voting equity interests by any person immediately after which such person beneficially owns more than 25% of the combined voting power of our then outstanding Common Units, unless such acquisition was made by (a) us or our subsidiaries, or any employee benefit plan maintained by us, our Operating Partnership or any of our subsidiaries, or (b) by any person in a transaction where (A) the existing holders prior to the transaction own at least 60% of the voting power of the entity surviving the transaction and (B) none of the Unitholders other than the Partnership, our subsidiaries, any employee benefit plan maintained by us, our Operating Partnership, or the surviving entity, or the existing beneficial owner of more than 25% of the outstanding Common Units owns more than 25% of the combined voting power of the surviving entity (such transaction, a ‘‘Non-Control Transaction’’); or (ii) approval by our partners of (a) merger, consolidation or reorganization involving the Partnership other than a Non-Control Transaction; (b) a complete liquidation or dissolution of the Partnership; or (c) the sale or other disposition of 50% or more of our net assets to any person (other than a transfer to a subsidiary).

Mr. Alexander also participates in the SERP, which provides retirement income which could not be provided under our qualified plans by reason of limitations contained in the IRC.

64

---

Table of Contents

Severance Protection Plan for Key Employees

Our officers and key employees are provided with employment protection following a ‘‘change of control’’ (the ‘‘Severance Protection Plan’’), as defined in the immediately preceding section. The Severance Protection Plan provides for severance payments equal to sixty-five (65) weeks of base pay and target bonuses for such officers and key employees following a ‘‘change of control’’ and termination of employment. This group comprises approximately forty-four (44) individuals. Pursuant to their severance protection agreements, Messrs. Dunn, Plante, Trautman and Jolly, as our executive officers, have been granted severance protection payments of seventy-eight (78) weeks of base pay and target bonuses following a ‘‘change of control’’ and termination of employment in lieu of participation in the Severance Protection Plan. Our Compensation Committee has also granted severance protection payments of seventy-eight (78) weeks to five (5) other executive officers who do not participate in the Severance Protection Plan.

On November 2, 2005, the Board of Supervisors approved an amendment to the Severance Protection Plan to provide that if any payment under the Severance Protection Plan subjects a participant to the 20% federal excise tax under IRC Section 409A, the payment will be increased to permit such participant to retain a net amount on an after-tax basis equal to what would be received had the excise tax not been payable.

Compensation Committee Interlocks and Insider Participation in Compensation Decisions

Compensation of our executive officers is determined by the Compensation Committee of our Board of Supervisors. The Compensation Committee is comprised of Messrs. Stookey, Mecum and Logan, none of whom is an officer or employee of the Partnership.

Compensation of Supervisors

Mr. Stookey, who is the Chairman of the Board of Supervisors, receives annual compensation of $100,000 for his services to us. Mr. Logan and Mr. Mecum, the other two Supervisors who are not salaried employees of the Partnership, receive $75,000 per year. All Supervisors who are not salaried employees of the Partnership receive reimbursement of reasonable out-of-pocket expenses incurred in connection with meetings of the Board of Supervisors. Neither Mr. Alexander nor Mr. Dunn, who are salaried employees of the Partnership, receive any additional compensation for serving as members of the Board of Supervisors. For the first quarter of fiscal 2006, the Board of Supervisors approved a per meeting fee for the Audit Committee of $2,500 for the Chairman of the Audit Committee (Mr. Logan), and $2,000 for each of the other Supervisors who serve on the Audit Committee (Messrs. Stookey and Mecum), for attendance at meetings of the Audit Committee held to evaluate certain potential transactions.  Under this arrangement, Mr. Logan received $25,000, Mr. Stookey received $18,000 and Mr. Mecum received $10,000. In the third quarter of fiscal 2006, the Board of Supervisors approved a per meeting fee in the same amounts for attendance at meetings of the Audit Committee held during the period February 2006 through October 2006 with respect to the GP Exchange Transaction. Under this arrangement, Mr. Logan received $22,500, Mr. Stookey $16,000 and Mr. Mecum $16,000.

Supervisors are able to purchase propane from the Operating Partnership at the employee price.

65

---

Table of Contents

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

The following table sets forth certain information as of December 7, 2006 regarding the beneficial ownership of Common Units by each member of the Board of Supervisors, each executive officer named in the Summary Compensation Table in Item II of this Annual Report, all members of the Board of Supervisors and executive officers as a group and each person or group known by us (based upon filings under Section 13(d) or (g) under the Exchange Act) to own beneficially more than 5% thereof. The business address of each individual or entity in the table is c/o Suburban Propane Partners, L.P., 240 Route 10 West, Whippany, New Jersey 07981-0206 and, except as set forth in the notes to the table, each individual or entity has sole voting and investment power over the Common Units reported.

Name of Beneficial Owner			Amount and Nature of Beneficial Ownership						Percent of Class
Mark A. Alexander (a) (b) (g)					1,055,010						3.2	%
Michael J. Dunn, Jr. (a) (g)					168,216							*
Robert M. Plante (c) (g)					94,300							*
Jeffrey S. Jolly (g)					94,241							*
Dennis W. Trautman (d)					5,953							*
John Hoyt Stookey (e)					11,519							*
Harold R. Logan, Jr. (e)					10,604							*
Dudley C. Mecum (e)					5,634							*
All Members of the Board of Supervisors and Executive Officers as a Group (13 persons) (f) (g)					1,624,141						5.0	%

*	Less than 1%.

(a)

Excludes the following numbers of Common Units as to which the following individuals deferred receipt as described below; Mr. Alexander – 243,902 and Mr. Dunn – 48,780. These Common Units are held in trust pursuant to a Compensation Deferral Plan, and Mr. Alexander and Mr. Dunn will have no voting or investment power over these Common Units until they are distributed by the trust. Mr. Alexander and Mr. Dunn have elected to receive the quarterly cash distributions on these deferred units. Notwithstanding the foregoing, if a ‘‘change of control’’ of the Partnership occurs (as defined in the Compensation Deferral Plan), all of the deferred Common Units (and related distributions) held in the trust automatically become distributable to such individuals.

(b)	Includes 784 Common Units held by the General Partner, of which, as an accommodation to the Partnership, Mr. Alexander is the sole member.

(c)	Excludes 2,753 unvested restricted units, none of which will vest in the 60-day period following December 7, 2006. Restricted unit grants vest 25%, 25% and 50%, respectively, on the third, fourth and fifth anniversaries of the date of grant and 100% upon a ‘‘change in control’’, as defined in the Partnership’s 2000 Restricted Unit Plan.

(d)	Excludes 35,245 unvested restricted units, none of which will vest in the 60-day period following December 7, 2006. Restricted unit grants vest 25%, 25% and 50%, respectively, on the third, fourth and fifth anniversaries of the date of grant and 100% upon a ‘‘change in control’’, as defined in the Partnership’s 2000 Restricted Unit Plan.

(e)	Excludes 8,500 unvested restricted units, none of which will vest in the 60-day period following December 7, 2006. Restricted unit grants vest 25%, 25% and 50%, respectively, on the third, fourth and fifth anniversaries of the date of grant and 100% upon a ‘‘change in control’’, as defined in the Partnership’s 2000 Restricted Unit Plan.

66

---

Table of Contents

(f)

Includes 3,657 unvested restricted units which will vest in the 60-day period following December 7, 2006. In addition to the units referred to in footnotes (a), (c), (d) and (e) above, the reported number of units also excludes 31,865 unvested restricted units, none of which will vest in the 60-day period following December 7, 2006, owned by certain executive officers, whose restricted units vest on the same basis as described in footnotes (c), (d) and (e) above.

(g)

Refer to Item 13 of this Annual Report for a description of certain lockup requirements pertaining to the Common Units issued to the General Partner under the GP Exchange Transaction. For Messrs. Alexander and Dunn, includes 1,025,226 and 168,216 Common Units, respectively, subject to a two-year lockup requirement from October 19, 2006. For Messrs. Plante and Jolly, includes 82,038 and 92,641 Common Units, respectively, subject to a 90-day lockup requirement from October 19, 2006. For the Executive Officers as a group, in addition to the Common Units for Messrs. Alexander, Dunn, Plante and Jolly, includes 159,016 Common Units subject to a 90-day lockup requirement from October 19, 2006.

Securities Authorized for Issuance Under the 2000 Restricted Unit Plan

The following table sets forth certain information, as of September 30, 2006, with respect to the Partnership’s 2000 Restricted Unit Plan, under which Restricted Units of the Partnership, as described in Note 10 to the Consolidated Financial Statements included in this Annual Report, are authorized for issuance.

Plan Category			Number of Common Units to be issued upon vesting of restricted units (a)						Weighted-average grant date fair value per restricted unit (b)						Number of restricted units remaining available for future issuance under the 2000 Restricted Unit Plan (excluding securities reflected in column(a)) (c)
Equity compensation plans approved by security holders(1)					340,786	(2)				$	29.28						308,919
Equity compensation plans not approved by security holders					—						—						—
Total					340,786					$	29.28						308,919

(1)	Relates to the 2000 Restricted Unit Plan.

(2)	Represents number of restricted units that, as of September 30, 2006, had been granted under the 2000 Restricted Unit Plan but had not yet vested.

67

---

Table of Contents

ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

Related Party Transactions    

Pursuant to the GP Exchange Transaction described in Item 1 of this Annual Report, on October 19, 2006 the Partnership issued 2,300,000 Common Units to the General Partner. Pursuant to the Distribution Agreement, on October 19, 2006 the Partnership filed a shelf registration statement with the SEC in order to register the resale by the individual members of the General Partner of the Common Units distributed to them by the General Partner. Upon the immediate effectiveness of the shelf registration statement, the General Partner distributed all but 784 Common Units to the then individual members of the General Partner in exchange for their interests in the General Partner. The Partnership has agreed to maintain the effectiveness of the registration statement for two years after October 19, 2006 (subject to the Board of Supervisors’ right to suspend its use under certain circumstances). Additionally, the Partnership agreed to indemnify the individual members of the General Partner, and the General Partner, against certain liabilities arising from the GP Exchange Transaction and the shelf registration statement, including liabilities that may arise under the securities laws.

The numbers of Common Units distributed to the Chief Executive Officer and our four other highly compensated executive officers, as well as the executive officers as a group following the GP Exchange Transaction were as follows. The three Supervisors who were not officers of the Partnership received no Common Units in the GP Exchange Transaction.

			Common Units Received in the GP Exchange Transaction
Mark A. Alexander (a)					1,026,010
Michael J. Dunn, Jr. (b)					168,216
Robert M. Plante					82,038
Jeffrey S. Jolly					92,641
Dennis W. Trautman					—
Executive Officers as a Group (a) (b)					1,527,921

(a)

Includes 784 Common Units held by the General Partner, of which, as an accommodation to the Partnership, Mr. Alexander is the sole member. Under the Distribution Agreement, the Partnership and the Operating Partnership have agreed to pay or reimburse Mr. Alexander for taxes imposed upon the General Partner by any state other than the state in which Mr. Alexander resides (except to the extent such taxes are attributable to activities or income of the General Partner that are unrelated to its ownership of the 784 Common Units or its status as General Partner).

(b)	Excludes 55,200 Common Units distributed to Mr. Dunn’s former wife.

Under the Distribution Agreement, the then individual members of the General Partner are subject to certain restrictions on the transfer of any of the Common Units distributed to them by the General Partner. Each of Messrs. Alexander and Dunn has agreed not to transfer any of the Common Units received by him in the GP Exchange Transaction for a period of two years from October 19, 2006, except: (i) to a family member, or trust for the benefit of a family member, of such individual who agrees to be bound by the lockup requirement; (ii) with the prior written consent of the Board of Supervisors of the Partnership; (iii) pursuant to a Change of Control (as defined in the Distribution Agreement); (iv) by will or the laws of intestacy to such person’s legal representative, heir or legatee; or (v) if such person is a partnership or corporation or similar entity, a distribution to its partners, stockholders, but subject to the terms of the lockup requirement. All other previous

68

---

Table of Contents

members of the General Partner agreed to not transfer any of the Common Units received by him or her in the GP Exchange Transaction for a period of 90 days following consummation of the GP Exchange Transaction except under the circumstances described in clauses (i) through (v) above.

Pursuant to the Partnership Agreement, the General Partner is neither required nor permitted to make any additional capital contributions to the Partnership, and the General Partner may not transfer the retained 784 Common Units nor acquire any additional Common Units. Any transfer by the General Partner of its general partnership interest in the Partnership is subject to the prior approval of the Board of Supervisors of the Partnership, except for a transfer by the General Partner of the entirety of such interest to an affiliate of the General Partner.

Additionally, the Board of Supervisors of the Partnership may, at any time, and for any reason, require the General Partner to transfer its general partnership interest in the Partnership or its Common Units to a designee of the Board of Supervisors. The consideration for the transfer of the general partnership interest in the Partnership shall be nominal. The consideration for the transfer of Common Units by the General Partner shall be the current market price of such Common Units. The Board of Supervisors may also, at any time and for any reason, require any or all of the members of the General Partner to transfer their limited liability company interests in the General Partner to a designee of the Board of Supervisors. The consideration for the transfer of limited liability company interests by the members of the General Partner shall be the product of (i) the member’s percentage interest in the General Partner multiplied by the number of Common Units owned by the General Partner and (ii) the current market price of the Common Units. If any such transfer is pursuant to or in connection with a merger or other transaction involving the Partnership, then the consideration for the Common Units owned by the General Partner shall be the consideration being paid on account of the Common Units in connection with the merger or such other transaction. Such consideration shall be paid in the form of cash or, at the option of the Board of Supervisors, in the form of consideration paid in the merger or other transaction.

The Partnership will continue its past practice of providing tax services to the General Partner at no cost to the General Partner and, in fiscal 2007, will continue to pay the cost of external tax return preparation services for the former members of the General Partner which amounted to approximately $46,500 in fiscal 2006.

The firm that served as financial advisor to the General Partner in connection with the GP Exchange Transaction has performed merger, acquisition and general financial advisory services for the Partnership in the past. The Partnership has agreed to retain the firm to continue to provide these services for fiscal 2007 through 2010 for an annual fee of $225,000. The Partnership has also agreed to indemnify the firm against various liabilities arising from its engagement by the Partnership, as well as from its engagement as financial advisor to the General Partner in connection with the GP Exchange Transaction.

Certain Relationships

During fiscal 2004, two relatives of the Partnership’s Chief Executive Officer purchased franchise interests in Suburban Cylinder Express, an indirect wholly-owned subsidiary of the Partnership, for the standard franchise fee of $35,000. Additionally, as part of the franchise agreement on an ongoing basis, the franchisees purchase propane from the Partnership in the normal course of business. The initial purchase price for the franchises was paid with funds received as a gift from the Partnership’s Chief Executive Officer. The Chief Executive Officer did not receive any economic interest in the franchises and recuses himself from any determinations that may be made by the Partnership concerning the franchises. The Partnership’s Audit Committee reviewed the terms of the foregoing arrangements and determined that these related parties have not received any preferential treatment.

By mutual agreement of the parties, the Partnership and one of the Chief Executive Officer’s relatives terminated their franchise agreement in March 2006. The Chief Executive Officer did not play any role in this termination, which was effected on terms no more favorable to the franchisee than similar franchise terminations effected by the Partnership with other franchisees over the prior twelve-month period.

69

---

Table of Contents

Supervisor Independence

The Board of Supervisors has determined that all three members of the Audit Committee, John Hoyt Stookey, Harold R. Logan, Jr. and Dudley C. Mecum, are audit committee financial experts and are independent within the meaning of the NYSE corporate governance listing standards and in accordance with Item 401 of Regulation S-K as of the date of this Annual Report. The Corporate Governance Guidelines and Principles adopted by the Board of Supervisors provide that a Supervisor is deemed to be lacking a material relationship to the Partnership and is therefore independent of management if the following criteria are satisfied:

1.	Within the past three years, the Supervisor:

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

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

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

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

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

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

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

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

70

---

Table of Contents

ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES

The following table sets forth the aggregate fees for services related to fiscal years 2006 and 2005 provided by PricewaterhouseCoopers LLP, our independent registered public accounting firm.

			Fiscal 2006						Fiscal 2005
Audit Fees (a)				$	2,510,000					$	3,117,745
Audit-Related Fees (b)					50,000						62,500
Tax Fees (c)					927,500						708,535
All Other Fees (d)					4,500						4,000

(a)	Audit Fees consist of professional services rendered for the integrated audit of our annual consolidated financial statements and our internal control over financial reporting, including reviews of our quarterly financial statements, as well as for services rendered in connection with the issuance of comfort letters and consents in connection with other filings made with the SEC.

(b)	Audit-Related Fees consist of fees billed for consultations concerning financial accounting and reporting standards.

(c)	Tax Fees consist of fees for professional services related to tax reporting, compliance and transaction services assistance.

(d)	All Other Fees represent fees for services provided to us not otherwise included in the categories above.

The Audit Committee of the Board of Supervisors has adopted a formal policy concerning the approval of audit and non-audit services to be provided by the principal accountant, PricewaterhouseCoopers LLP. The policy requires that all services PricewaterhouseCoopers LLP may provide to us, including audit services and permitted audit-related and non-audit services, be pre-approved by the Audit Committee. The Audit Committee pre-approved all audit and non-audit services provided by PricewaterhouseCoopers LLP during fiscal 2006 and fiscal 2005.

71

---

Table of Contents

PART IV

ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES

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

	1.	Financial Statements

See ‘‘Index to Financial Statements’’ set forth on page F-1.

	2.	Financial Statement Schedule

See ‘‘Index to Financial Statement Schedule’’ set forth on page S-1.

	3.	Exhibits

See ‘‘Index to Exhibits’’ set forth on page E-1.

72

---

Table of Contents

SIGNATURES

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

SUBURBAN PROPANE PARTNERS, L.P.

Date: December 14, 2006			By:			/s/ MARK A. ALEXANDER
						Mark A. Alexander Chief Executive Officer and Appointed Supervisor

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

Signature		Title		Date
By:    /s/ MARK A. ALEXANDER		Chief Executive Officer and Appointed Supervisor		December 14, 2006
(Mark A. Alexander)
By:    /s/ MICHAEL J. DUNN, JR		President and Appointed Supervisor		December 14, 2006
(Michael J. Dunn, Jr.)
By:    /s/ JOHN HOYT STOOKEY		Chairman and Elected Supervisor		December 14, 2006
(John Hoyt Stookey)
By:    /s/ HAROLD R. LOGAN, JR.		Elected Supervisor		December 14, 2006
(Harold R. Logan, Jr.)
By:    /s/ DUDLEY C. MECUM		Elected Supervisor		December 14, 2006
(Dudley C. Mecum)
By:    /s/ ROBERT M. PLANTE		Vice President and Chief Financial Officer		December 14, 2006
(Robert M. Plante)
By:    /s/ MICHAEL A. STIVALA		Controller and Chief Accounting Officer		December 14, 2006
(Michael A. Stivala)

73

---

Table of Contents

INDEX TO EXHIBITS

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

Exhibit Number			Description
2.1			Exchange Agreement dated as of July 27, 2006 by and among the Partnership, the Operating Partnership and the General Partner. (Incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed July 28, 2006).
3.1			Third Amended and Restated Agreement of Limited Partnership of the Partnership dated as of October 19, 2006. (Incorporated by reference to Exhibit 3.1 to the Partnership’s Current Report on Form 8-K filed October 19, 2006).
3.2			Third Amended and Restated Agreement of Limited Partnership of the Operating Partnership dated as of October 19, 2006. (Incorporated by reference to Exhibit 3.2 to the Partnership’s Current Report on Form 8-K filed October 19, 2006).
4.1			Description of Common Units of the Partnership. (Incorporated by reference to Exhibit 4.1 to the Partnership’s Current Report on Form 8-K filed October 19, 2006).
4.2			Indenture, dated as of December 23, 2003, between Suburban Propane Partners, L.P., Suburban Energy Finance Corp. and The Bank of New York, as Trustee (including Form of Senior Global Exchange Note). (Incorporated by reference to Exhibit 10.28 to the Partnership’s Quarterly Report on Form 10-Q For the fiscal quarter ended December 27, 2003).
4.3			Exchange and Registration Rights Agreement, dated December 23, 2003 among Suburban Propane Partners, L.P., Suburban Energy Finance Corp., Wachovia Capital Markets, LLC and Goldman, Sachs & Co. (Incorporated by reference to Exhibit 4.1 to the Partnership’s Registration Statement on Form S-4 dated December 19, 2003).
4.4			Exchange and Registration Rights Agreement, dated March 31, 2005 among Suburban Propane Partners, L.P., Suburban Energy Finance Corp., Wachovia Capital Markets, LLC and Goldman, Sachs & Co. (Incorporated by reference to Exhibit 4.1 to the Partnership’s Current Report of Form 8-K filed April 1, 2005).
10.1			Employment Agreement dated as of March 5, 1996 between the Operating Partnership and Mr. Alexander. (Incorporated by reference to Exhibit 10.13 to the Partnership’s Current Report on Form 8-K filed April 29, 1996).
10.2			First Amendment to Employment Agreement dated as of March 5, 1996 between the Operating Partnership and Mr. Alexander entered into as of October 23, 1997. (Incorporated by reference to Exhibit 10.13 to the Partnership’s Current Report on Form 8-K filed April 29, 1996).
10.3			Second Amendment to Employment Agreement dated as of March 5, 1996 between the Operating Partnership and Mr. Alexander entered into as of April 14, 1999. (Incorporated by reference to Exhibit 10.15 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 27, 1997).
10.4			Form of Third Amendment to Employment Agreement dated as of March 5, 1996 between the Operating Partnership and Mr. Alexander, entered into November 2, 2005. (Incorporated by reference to Exhibit 10.4 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 24, 2005).

E-1

---

Table of Contents

Exhibit Number			Description
10.5			Suburban Propane Partners, L.P. 2000 Restricted Unit Plan, as amended and restated effective October 17, 2006. (Incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed October 19, 2006).
10.6			Suburban Propane, L.P. Severance Protection Plan dated September 1996. (Incorporated by reference to Exhibit 10.12 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 28, 1996).
10.7			Form of Amendment to Suburban Propane Severance Protection Plan for Key Employees, adopted November 2, 2005. (Incorporated by reference to Exhibit 10.7 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 24, 2005).
10.8			Suburban Propane, L.P. Long Term Incentive Plan, as amended and restated effective October 1, 1999. (Incorporated by reference to Exhibit 10.19 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 28, 2002).
10.9			Form of Amendment to Suburban Propane, L.P. Long Term Incentive Program, adopted November 2, 2005. (Incorporated by reference to Exhibit 10.9 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 24, 2005).
10.10			Suburban Propane L.P. 2003 Long Term Incentive Plan. (Incorporated by reference to Exhibit 10.7 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 25, 2004).
10.11			Form of Amendment to Suburban Propane, L.P. 2003 Long Term Incentive Program, adopted October 17, 2006. (Filed herewith).
10.12			Benefits Protection Trust dated May 26, 1999 by and between Suburban Propane Partners, L.P. and First Union National Bank. (Incorporated by reference to the Partnership’s Quarterly Report on Form 10-Q for the fiscal quarter ended June 26, 1999).
10.13			Compensation Deferral Plan of Suburban Propane Partners, L.P. and Suburban Propane, L.P. amended and restated as of January 1, 2004. (Incorporated by reference to Exhibit 10.9 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 25, 2004).
10.14			Form of Amendment to Compensation Deferral Plan of Suburban Propane Partners, L.P. and Suburban Propane, L.P., adopted November 2, 2005. (Incorporated by reference to Exhibit 10.13 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 24, 2005).
10.15			Amended and Restated Supplemental Executive Retirement Plan of the Partnership (effective as of January 1, 1998). (Incorporated by reference to Exhibit 10.23 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 29, 2001).
10.16			Amended and Restated Retirement Savings and Investment Plan of Suburban Propane effective as of January 1, 1998). (Incorporated by reference to Exhibit 10.24 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 29, 2001).
10.17			Amendment No. 1 to the Retirement Savings and Investment Plan of Suburban Propane (effective January 1, 2002). (Incorporated by reference to Exhibit 10.25 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 28, 2002).
10.18			Third Amended and Restated Credit Agreement dated October 20, 2004, as amended by the First Amendment thereto dated March 17, 2005, as further amended by the Second Amendment thereto dated August 25, 2005. (Incorporated by reference to the Partnership’s Current Report on Form 8-K filed August 29, 2005).

E-2

---

Table of Contents

Exhibit Number			Description
10.19			First Amendment to the Third Amended and Restated Credit Agreement dated as of March 11, 2005. (Incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed April 1, 2005).
10.20			Second Amendment to the Third Amended and Restated Credit Agreement dated as of August 26, 2005. (Incorporated by reference to the Partnership’s Current Report on Form 8-K filed August 29, 2005).
10.21			Third Amendment to the Third Amended and Restated Credit Agreement dated as of February 9, 2006. (Incorporated by reference to the Partnership’s Current Report on Form 8-K filed February 24, 2006).
10.22			Asset Purchase Agreement by and among Agway Energy Products, LLC, Agway Energy Services, Inc., Agway Energy Services PA, Inc., Agway, Inc. and Suburban Propane, L.P., dated as of November 10, 2003. (Incorporated by reference to Exhibit 10.28 to the Partnership’s Current Report on Form 8-K filed December 5, 2003).
10.23			Distribution, Release and Lockup Agreement, dated as of July 27, 2006, between the Partnership, the Operating Partnership, the General Partner and the members of the General Partner. (Incorporated by reference to Exhibit 10.2 to the Partnership’s Current Report on Form 8-K filed July 28, 2006).
21.1			Subsidiaries of Suburban Propane Partners, L.P. (Filed herewith).
23.1			Consent of Independent Registered Public Accounting Firm. (Filed herewith).
31.1			Certification of the Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. (Filed herewith).
31.2			Certification of the Vice President and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. (Filed herewith).
32.1			Certification of the Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (Filed herewith).
32.2			Certification of the Vice President and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (Filed herewith).

E-3

---

INDEX TO FINANCIAL STATEMENTS

SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES

			Page
Report of Independent Registered Public Accounting Firm.					F-2
Consolidated Balance Sheets – As of September 30, 2006 and September 24, 2005					F-4
Consolidated Statements of Operations – Years Ended September 30, 2006, September 24, 2005 and September 25, 2004.					F-5
Consolidated Statements of Cash Flows – Years Ended September 30, 2006, September 24, 2005 and September 25, 2004					F-6
Consolidated Statements of Partners’ Capital – Years Ended September 30, 2006, September 24, 2005 and September 25, 2004					F-7
Notes to Consolidated Financial Statements					F-8

F-1

---

Table of Contents

Report of Independent Registered Public Accounting Firm

To the Board of Supervisors and Unitholders of
Suburban Propane Partners, L.P.:

We have completed integrated audits of Suburban Propane Partners, L.P.’s 2006 and 2005 consolidated financial statements and of its internal control over financial reporting as of September 30, 2006, and an audit of its 2004 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

Consolidated financial statements and financial statement schedule

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Suburban Propane Partners, L.P. and its subsidiaries (the ‘‘Partnership’’) at September 30, 2006 and September 24, 2005 and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2006 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

Internal control over financial reporting

Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A, that Suburban Propane Partners, L.P. maintained effective internal control over financial reporting as of September 30, 2006 based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of September 30, 2006, based on criteria established in Internal Control – Integrated Framework issued by the COSO. The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Partnership’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal

F-2

---

Table of Contents

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

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

PricewaterhouseCoopers LLP
Florham Park, New Jersey
December 14, 2006

F-3

---

Table of Contents

SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(in thousands)

			September 30, 2006						September 24, 2005
ASSETS
Current assets:
Cash and cash equivalents				$	60,571					$	14,411
Accounts receivable, less allowance for doubtful accounts of $5,530 and $9,965, respectively					78,547						109,918
Inventories					79,418						80,565
Prepaid expenses and other current assets					16,815						31,909
Total current assets					235,351						236,803
Property, plant and equipment, net					390,383						399,985
Goodwill					281,359						281,359
Other intangible assets, net					18,098						20,685
Other assets					28,695						26,765
Total assets				$	953,886					$	965,597
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable				$	57,372					$	63,569
Accrued employment and benefit costs					35,510						20,291
Short-term borrowings					—						26,750
Current portion of long-term borrowings					—						475
Accrued insurance					7,360						11,505
Customer deposits and advances					62,630						62,099
Accrued interest					8,371						10,975
Other current liabilities					21,373						26,548
Total current liabilities					192,616						222,212
Long-term borrowings					548,304						548,070
Postretirement benefits obligation					27,759						31,058
Accrued insurance					38,053						34,952
Accrued pension liability					31,086						40,206
Other liabilities					15,367						12,983
Total liabilities					853,185						889,481
Commitments and contingencies
Partners’ capital:
Common Unitholders (30,314 and 30,279 units issued and outstanding at September 30, 2006 and September 24, 2005, respectively)					170,151						159,199
General Partner					(1,969	)					(1,779	)
Deferred compensation					(5,704	)					(5,887	)
Common Units held in trust, at cost					5,704						5,887
Unearned compensation					—						(4,355	)
Accumulated other comprehensive loss					(67,481	)					(76,949	)
Total partners’ capital					100,701						76,116
Total liabilities and partners’ capital				$	953,886					$	965,597

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

F-4

---

Table of Contents

SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per unit amounts)

			Year Ended
			September 30, 2006						September 24, 2005						September 25, 2004
Revenues
Propane				$	1,086,083					$	969,943					$	856,109
Fuel oil and refined fuels					356,531						431,223						281,682
Natural gas and electricity					122,071						102,803						68,452
HVAC					87,258						106,115						92,072
All other					9,697						10,150						8,939
					1,661,640						1,620,234						1,307,254
Costs and expenses
Cost of products sold					1,051,797						1,069,745						783,552
Operating					374,871						393,738						357,173
General and administrative					63,561						47,191						53,888
Restructuring costs (Note 7)					6,076						2,775						2,942
Impairment of goodwill (Note 6)					—						656						3,177
Depreciation and amortization					33,151						37,762						36,743
					1,529,456						1,551,867						1,237,475
Income before interest expense and provision for income taxes					132,184						68,367						69,779
Loss on debt extinguishment					—						36,242						—
Interest income					(630	)					(310	)					(429	)
Interest expense					41,310						40,684						41,261
Income (loss) before provision for income taxes					91,504						(8,249	)					28,947
Provision for income taxes					764						803						3
Income (loss) from continuing operations					90,740						(9,052	)					28,944
Discontinued operations (Note 17):
Gain on sale of customer service centers					—						976						26,332
Loss from discontinued service centers					—						—						(972	)
Net income (loss)				$	90,740					$	(8,076	)				$	54,304
General Partner’s interest in net income (loss)				$	2,628					$	(251	)				$	1,310
Limited Partners’ interest in net income (loss)				$	88,112					$	(7,825	)				$	52,994
Income (loss) per Common Unit – basic
Income (loss) from continuing operations				$	2.84					$	(0.29	)				$	0.96
Discontinued operations					—						0.03						0.83
Net income (loss)				$	2.84					$	(0.26	)				$	1.79
Weighted average number of Common Units outstanding – basic					30,310						30,276						29,599
Income (loss) per Common Unit – diluted
Income (loss) from continuing operations				$	2.83					$	(0.29	)				$	0.96
Discontinued operations					—						0.03						0.82
Net income (loss)				$	2.83					$	(0.26	)				$	1.78
Weighted average number of Common Units outstanding – diluted					30,453						30,276						29,705

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

F-5

---

Table of Contents

SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)

			Year Ended
			September 30, 2006						September 24, 2005						September 25, 2004
Cash flows from operating activities:
Net income (loss)				$	90,740					$	(8,076	)				$	54,304
Adjustments to reconcile net income to net cash provided by operations:
Depreciation expense					30,564						32,865						33,344
Amortization of intangible assets					2,587						4,897						3,399
Amortization of debt origination costs					1,324						1,514						1,421
Compensation cost recognized under Restricted Unit Plan					2,221						1,806						1,171
Amortization of discount on long-term borrowings					234						117						—
Gain on disposal of property, plant and equipment, net					(1,000	)					(2,043	)					(715	)
Gain on sale of customer service centers					—						(976	)					(26,332	)
Pension settlement charge					4,437						—						5,337
Impairment of goodwill					—						656						3,177
Loss on debt extinguishment					—						36,242						—
Changes in assets and liabilities, net of businesses acquired and of dispositions:
Decrease (increase) in accounts receivable					31,371						(18,918	)					10,047
Decrease (increase) in inventories					1,147						(16,424	)					(10,677	)
Decrease (increase) in prepaid expenses and other current assets					15,745						4,315						(13,155	)
(Decrease) increase in accounts payable					(6,197	)					3,326						17,603
Increase (decrease) in accrued employment and benefit costs					15,219						(4,861	)					1,024
(Decrease) increase in accrued interest					(2,604	)					908						2,610
(Decrease) increase in other accrued liabilities					(11,325	)					(5,989	)					20,233
(Increase) decrease in other noncurrent assets					(2,072	)					(3,552	)					619
(Decrease) increase in other noncurrent liabilities					(2,070	)					13,198						(10,345	)
Net cash provided by operating activities					170,321						39,005						93,065
Cash flows from investing activities:
Capital expenditures					(23,057	)					(29,301	)					(26,527	)
Acquisition of Agway Energy, net of cash acquired					—						—						(211,181	)
Proceeds from sale of property, plant and equipment					3,965						4,670						1,799
Proceeds from sale of customer service centers, net					—						—						39,352
Net cash used in investing activities					(19,092	)					(24,631	)					(196,557	)
Cash flows from financing activities:
Long-term debt repayments					(475	)					(340,440	)					(42,911	)
Long-term debt issuance					—						372,953						175,000
Short-term (repayments) borrowings					(26,750	)					26,750						—
Expenses associated with debt agreements					—						(4,175	)					(5,947	)
Prepayment premium associated with debt extinguishment					—						(31,980	)					—
Net proceeds from issuance of Common Units					—						—						87,566
Partnership distributions					(77,844	)					(76,552	)					(72,500	)
Net cash (used in) provided by financing activities					(105,069	)					(53,444	)					141,208
Net increase (decrease) in cash and cash equivalents					46,160						(39,070	)					37,716
Cash and cash equivalents at beginning of year					14,411						53,481						15,765
Cash and cash equivalents at end of year				$	60,571					$	14,411					$	53,481
Supplemental disclosure of cash flow information:
Cash paid for interest				$	41,241					$	42,457					$	35,252
Non-cash adjustment for minimum pension liability				$	(4,441	)				$	(1,242	)				$	2,096

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

F-6

---

Table of Contents

SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(in thousands)

			Number of Common Units						Common Unitholders						General Partner						Deferred Compen- sation						Common Units Held in Trust						Unearned Compen- sation						Accumulated Other Compre- hensive (Loss) Income						Total Partners’ Capital						Compre- hensive Income (Loss)
Balance at September 27, 2003					27,256					$	165,950					$	1,567					$	(5,795	)				$	5,795					$	(2,171	)				$	(81,268	)				$	84,078
Net income											52,994						1,310																														54,304					$	54,304
Other comprehensive income:
Net unrealized gains on cash flow hedges																																									9,129						9,129						9,129
Reclassification of realized losses on cash flow hedges into earnings																																									1,129						1,129						1,129
Non-cash pension settlement charge																																									5,337						5,337						5,337
Minimum pension liability adjustment																																									(2,096	)					(2,096	)					(2,096	)
Total comprehensive income																																																				$	67,803
Partnership distributions											(70,475	)					(2,025	)																													(72,500	)
Sale of Common Units under public offering, net of offering expenses					2,990						87,566																																				87,566
Common Units issued under Restricted Unit Plan					11
Common Units distributed into trust																							(159	)					159																		—
Distribution of Common Units held in trust																							176						(176	)																	—
Grants issued under Restricted Unit Plan, net of forfeitures											2,845																								(2,845	)											—
Amortization of Restricted Unit Plan, net of forfeitures																																			1,171												1,171
Balance at September 25, 2004					30,257						238,880						852						(5,778	)					5,778						(3,845	)					(67,769	)					168,118
Net loss											(7,825	)					(251	)																													(8,076	)				$	(8,076	)
Other comprehensive loss:
Net unrealized losses on cash flow hedges																																									(1,293	)					(1,293	)					(1,293	)
Reclassification of realized gains on cash flow hedges into earnings																																									(9,129	)					(9,129	)					(9,129	)
Minimum pension liability adjustment																																									1,242						1,242						1,242
Total comprehensive loss																																																				$	(17,256	)
Partnership distributions											(74,172	)					(2,380	)																													(76,552	)
Common Units issued under Restricted Unit Plan					22
Common Units distributed into trust																							(109	)					109																		—
Grants issued under Restricted Unit Plan, net of forfeitures											2,316																								(2,316	)											—
Amortization of Restricted Unit Plan, net of forfeitures																																			1,806												1,806
Balance at September 24, 2005					30,279						159,199						(1,779	)					(5,887	)					5,887						(4,355	)					(76,949	)					76,116
Net income											88,112						2,628																														90,740					$	90,740
Other comprehensive income:
Net unrealized gains on cash flow hedges																																									590						590						590
Reclassification of realized gains on cash flow hedges into earnings																																									—						—						—
Non-cash pension settlement charge																																									4,437						4,437						4,437
Minimum pension liability adjustment																																									4,441						4,441						4,441
Total comprehensive income																																																				$	100,208
Partnership distributions											(75,026	)					(2,818	)																													(77,844	)
Common Units issued under Restricted Unit Plan					35
Common Units distributed into trust																							183						(183	)																	—
Elimination of unearned compensation from adoption of SFAS 123R											(4,355	)																							4,355												—
Compensation cost recognized under Restricted Unit Plan, net of forfeitures											2,221																								—												2,221
Balance at September 30, 2006					30,314					$	170,151					$	(1,969	)				$	(5,704	)				$	5,704					$	—					$	(67,481	)				$	100,701

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

F-7

---

Table of Contents

SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands, except per unit amounts)

1.	Partnership Organization and Formation

Suburban Propane Partners, L.P. (the ‘‘Partnership’’) is a publicly traded Delaware limited partnership principally engaged, through its operating partnership and subsidiaries, in the retail marketing and distribution of propane, fuel oil and refined fuels, as well as the marketing of natural gas and electricity in deregulated markets. In addition, to complement its core marketing and distribution businesses, the Partnership services a wide variety of home comfort equipment, particularly for heating, ventilation and air conditioning (‘‘HVAC’’). The publicly traded limited partner interests in the Partnership are evidenced by common units traded on the New York Stock Exchange (‘‘Common Units’’), with 30,314,262 Common Units outstanding at September 30, 2006. The holders of Common Units are entitled to participate in distributions and exercise the rights and privileges available to limited partners under the Third Amended and Restated Agreement of Limited Partnership (the ‘‘Partnership Agreement’’), adopted on October 19, 2006 following approval by Common Unitholders at the Partnership’s Tri-Annual Meeting. Rights and privileges under the Partnership Agreement include, among other things, the election of all members of the Board of Supervisors and voting on the removal of the general partner.

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

The general partner of both the Partnership and the Operating Partnership is Suburban Energy Services Group LLC (the ‘‘General Partner’’), a Delaware limited liability company. On October 19, 2006, the Partnership consummated an agreement with its General Partner to exchange 2,300,000 newly issued Common Units for the General Partner’s incentive distribution rights (‘‘IDRs’’) and the economic interest in the Partnership and the Operating Partnership included in the general partner interests therein (the ‘‘GP Exchange Transaction’’). Prior to the GP Exchange Transaction, the General Partner was majority-owned by senior management of the Partnership and owned 224,625 general partner units (an approximate 0.74% ownership interest) in the Partnership and a 1.0101% general partner interest in the Operating Partnership. The General Partner also held all outstanding IDRs and appointed two of the five members of the Board of Supervisors. As a result of the GP Exchange Transaction, the General Partner will have no economic interest in either the Partnership or the Operating Partnership other than as a holder of 784 Common Units that will remain in the General Partner, there will no longer be any IDRs outstanding and the sole member of the General Partner is the Partnership’s Chief Executive Officer.

On January 5, 2001, Suburban Holdings, Inc., a subsidiary of the Operating Partnership, was formed to hold the stock of Gas Connection, Inc. (d/b/a HomeTown Hearth & Grill), Suburban @ Home, Inc. and Suburban Franchising, Inc. HomeTown Hearth & Grill sells and installs natural gas and propane gas grills, fireplaces and related accessories and supplies. Suburban @ Home sells, installs, services and repairs a full range of HVAC products. Suburban Franchising creates and develops propane related franchising business opportunities.

On November 21, 2003, Suburban Heating Oil Partners, LLC, a subsidiary of HomeTown Hearth & Grill, was formed to acquire and operate the fuel oil and refined fuels and HVAC assets and businesses of Agway Energy acquired on December 23, 2003 (see Note 3). In addition, Agway Energy Services, LLC, also a subsidiary of HomeTown Hearth & Grill, was formed to acquire and operate the natural gas and electricity marketing business of Agway Energy.

F-8

---

Table of Contents

Suburban Energy Finance Corporation, a direct wholly-owned subsidiary of the Partnership, was formed on November 26, 2003 to serve as co-issuer, jointly and severally with the Partnership, of the Partnership’s 6.875% senior notes due in 2013 (see Note 9).

The Partnership serves more than 1,000,000 active residential, commercial, industrial and agricultural customers from more than 300 locations in 30 states. The Partnership’s operations are concentrated in the east and west coast regions of the United States. No single customer accounted for 10% or more of the Partnership’s revenues during fiscal 2006, 2005 or 2004. During fiscal 2006, 2005 and 2004, three suppliers provided approximately 35%, 33% and 36%, respectively, of the Partnership’s total domestic propane supply. The Partnership believes that, if supplies from any of these three suppliers were interrupted, it would be able to secure adequate propane supplies from other sources without a material disruption of its operations.

2.	Summary of Significant Accounting Policies

Principles of Consolidation.    The consolidated financial statements include the accounts of the Partnership and all of its direct and indirect subsidiaries. All significant intercompany transactions and account balances have been eliminated. The Partnership consolidates the results of operations, financial condition and cash flows of the Operating Partnership as a result of the Partnership’s 98.9899% limited partner interest in the Operating Partnership and its ability to influence control over the major operating and financial decisions through the powers of the Board of Supervisors provided for in the Partnership Agreement. As a result of the GP Exchange Transaction (see Note 1 and Note 19), the Partnership will own all of the economic interest in the Operating Partnership through its 100% limited partner interest. The General Partner will no longer have any economic interest in the Partnership or the Operating Partnership.

Fiscal Period.    The Partnership’s fiscal year ends on the last Saturday nearest to September 30. As fiscal 2006 ended on September 30, fiscal 2006 includes 53 weeks of operations compared to 52 weeks in each of fiscal 2005 and fiscal 2004.

Revenue Recognition.    Sales of propane, fuel oil and refined fuels are recognized at the time product is delivered to the customer. Revenue from the sale of appliances and equipment is recognized at the time of sale or when installation is complete, as applicable. Revenue from repairs, maintenance and other service activities is recognized upon completion of the service. Revenue from HVAC service contracts is recognized ratably over the service period. Revenue from the natural gas and electricity business is recognized based on customer usage as determined by meter readings, plus an amount for natural gas and electricity delivered but unbilled at the end of each accounting period.

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

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

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

Derivative Instruments and Hedging Activities.    The Partnership enters into a combination of exchange-traded futures and option contracts, forward contracts and in certain instances, over-the-counter options (collectively, ‘‘derivative instruments’’) to manage the price risk associated

F-9

---

Table of Contents

with future purchases of the commodities used in its operations, principally propane and fuel oil, as well as to ensure supply during periods of high demand. All derivative instruments are reported on the consolidated balance sheet, within other current assets or other current liabilities, at their fair values pursuant to Statement of Financial Accounting Standards (‘‘SFAS’’) No. 133, ‘‘Accounting for Derivative Instruments and Hedging Activities,’’ as amended by SFAS Nos. 137, 138, 149 and 155 (‘‘SFAS 133’’). On the date that futures, forward and option contracts are entered into, the Partnership makes a determination as to whether the derivative instrument qualifies for designation as a hedge. Changes in the fair value of derivative instruments are recorded each period in current period earnings or other comprehensive income (loss) (‘‘OCI’’), depending on whether a derivative instrument is designated as a hedge and, if so, the type of hedge. For derivative instruments designated as cash flow hedges, the Partnership formally assesses, both at the hedge contract’s inception and on an ongoing basis, whether the hedge contract is highly effective in offsetting changes in cash flows of hedged items. Changes in the fair value of derivative instruments designated as cash flow hedges are reported in OCI to the extent effective and reclassified into cost of products sold during the same period in which the hedged item affects earnings. Beginning with the fiscal 2006 third quarter, the Partnership reports all unrealized (non-cash) gains or losses attributable to the mark-to-market on derivative instruments within cost of products sold. Unrealized gains or losses for all prior years presented have been reclassified from operating expenses to cost of products sold for comparative purposes. The mark-to-market gains or losses on ineffective portions of cash flow hedges used to hedge future purchases are recognized in cost of products sold immediately. Changes in the fair value of derivative instruments that are not designated as hedges are recorded in current period earnings within cost of products sold.

A portion of the Partnership’s option contracts are not classified as hedges and, as such, changes in the fair value of these derivative instruments are recognized within cost of products sold as they occur. The value of certain option contracts that do qualify as hedges and are designated as cash flow hedges under SFAS 133 have two components of value: time value and intrinsic value. The intrinsic value is the value by which the option is in the money (i.e., the amount by which the value of the commodity exceeds the exercise or ‘‘strike’’ price of the option). The remaining amount of option value is attributable to time value. The Partnership does not include the time value of option contracts in its assessment of hedge effectiveness and, therefore, records changes in the time value component of the options currently in earnings.

Market risks associated with the trading of futures, options and forward contracts are monitored daily for compliance with the Partnership’s Hedging and Risk Management Policy which includes volume limits for open positions. Open inventory positions are also reviewed and managed daily as to exposures to changing market prices.

A portion of the Partnership’s long-term borrowings bear interest at a variable rate based upon either LIBOR or Wachovia National Bank’s prime rate, plus an applicable margin depending on the level of the Partnership’s total leverage. Therefore, the Partnership is subject to interest rate risk on the variable component of the interest rate. The Partnership manages part of its variable interest rate risk by entering into interest rate swap agreements. On March 31, 2005, the Partnership entered into a $125,000 interest rate swap contract in conjunction with the Term Loan facility under the Revolving Credit Agreement (see Note 9). The interest rate swap is being accounted for under SFAS 133 and the Partnership has designated the interest rate swap as a cash flow hedge. Changes in the fair value of the interest rate swap are recognized in OCI until the hedged item is recognized in earnings.

Long-Lived Assets.    Long-lived assets include:

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

F-10

---

Table of Contents

Depreciation is determined for related groups of assets under the straight-line method based upon their estimated useful lives as follows:

Buildings			40 Years
Building and land improvements			10-40 Years
Transportation equipment			4-30 Years
Storage facilities			7-40 Years
Office equipment			3-7 Years
Tanks and cylinders			13-40 Years
Computer software			3-7 Years

The weighted average estimated useful life of the Partnership’s tanks and cylinders is approximately 25 years.

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

Goodwill.    Goodwill represents the excess of the purchase price over the fair value of net assets acquired. Goodwill is subject to an impairment review at a reporting unit level, on an annual basis in August of each year, or when an event occurs or circumstances change that would indicate potential impairment. The Partnership assesses the carrying value of goodwill at a reporting unit level based on an estimate of the fair value of the respective reporting unit. Fair value of the reporting unit is estimated using discounted cash flow analyses taking into consideration estimated cash flows in a ten-year projection period and a terminal value calculation at the end of the projection period. If the fair value of the reporting unit exceeds its carrying value, the goodwill associated with the reporting unit is not considered to be impaired. If the carrying value of the reporting unit exceeds its fair value, an impairment loss is recognized to the extent that the carrying amount of the associated goodwill, if any, exceeds the implied fair value of the goodwill.

Other Intangible Assets.    Other intangible assets consist of non-compete agreements and acquired leasehold interests, customer lists and tradenames. Non-compete agreements are amortized under the straight-line method over the periods of the related agreements, ending periodically between fiscal years 2007 and 2010. Leasehold interests are amortized under the straight-line method over the shorter of the lease term or the useful life of the related assets, through fiscal 2025. Customer lists and tradenames are amortized under the straight-line method over the estimated period for which the assets are expected to contribute to the future cash flows of the reporting entities to which they relate, ending periodically between fiscal years 2012 and 2019.

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

F-11

---

Table of Contents

within other assets related to the amount of the liability expected to be covered by insurance. Claims are generally settled within 5 years of origination.

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

Environmental Reserves.    The Partnership establishes reserves for environmental exposures when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated based upon the Partnership’s best estimate of costs associated with environmental remediation and ongoing monitoring activities. Accrued environmental reserves are exclusive of claims against third parties, and an asset is established where contribution or reimbursement from such third parties has been agreed and the Partnership is reasonably assured of receiving such contribution or reimbursement. Environmental reserves are not discounted.

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

Income taxes for the Corporate Entities are provided based on the asset and liability approach to accounting for income taxes. Under this method, deferred tax assets and liabilities are recognized for the expected future tax consequences of differences between the carrying amounts and the tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period when the change is enacted.

Asset Retirement Obligations.    Effective September 29, 2002, the Partnership adopted SFAS No. 143, ‘‘Accounting for Asset Retirement Obligations,’’ (‘‘SFAS 143’’) which established financial accounting and reporting standards for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The provisions of this statement apply to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of a long-lived asset, except for certain obligations of lessees. The Partnership did not recognize any asset retirement obligations under SFAS 143 because settlement dates for the retirement obligations encountered could not be readily estimated or determined.

In March 2005, the Financial Accounting Standards Board (‘‘FASB’’) issued FASB Interpretation No. 47, ‘‘Accounting for Conditional Asset Retirement Obligations’’ (‘‘FIN 47’’). FIN 47 clarifies that the term ‘‘conditional asset retirement obligation’’ as used in SFAS 143 represents a legal obligation to perform an asset retirement activity for which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Since the obligation to perform the asset retirement activity is unconditional, FIN 47 provides that a liability for the fair value of a conditional asset retirement obligation should be recognized if its fair value can be reasonably estimated, even though uncertainty exists about the timing and/or method of its settlement. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of a conditional asset retirement obligation under SFAS 143. Under this interpretation, the Partnership has recognized asset retirement obligations for certain costs of contractually mandated removal of

F-12

---

Table of Contents

leasehold improvements and certain costs to remove and properly dispose of underground and aboveground fuel oil storage tanks. FIN 47 became effective for the Partnership’s fiscal year ended September 30, 2006.

The Partnership records a liability at fair value for the estimated cost to retire a tangible long-lived asset at the time that liability is incurred, which is generally when the asset is purchased, constructed or leased. The Partnership records the liability, which is referred to as an asset retirement obligation, when it has a legal obligation, as defined in SFAS 143, to incur costs to retire the asset and when a reasonable estimate of the fair value of the liability can be made. If a reasonable estimate cannot be made at the time the liability is incurred, the Partnership records the liability when sufficient information is available to estimate the liability’s fair value.

As of September 30, 2006, the Partnership recognized an asset retirement obligation of $1,064 on the consolidated balance sheet within other liabilities for the removal of leasehold improvements and for the removal and disposal of underground and aboveground fuel oil storage tanks, and an increase to property, plant and equipment of $650. The implementation of FIN 47 resulted in a charge of approximately $414 which, because of its insignificance, was included in the consolidated statements of operations within operating expenses.

Unit-Based Compensation.    The Partnership accounts for unit-based compensation in accordance with the revised SFAS No. 123, ‘‘Share-Based Payment’’ (‘‘SFAS 123R’’) which was adopted by the Partnership effective for the first quarter of fiscal 2006 ended December 24, 2005. Prior to adoption, the Partnership accounted for unit-based compensation plans under the provisions of Accounting Principles Board Opinion No. 25, ‘‘Accounting for Stock Issued to Employees,’’ and related interpretations and followed the disclosure only provision of SFAS No. 123, ‘‘Accounting for Stock-Based Compensation’’. SFAS 123R requires the recognition of compensation cost over the respective service period for employee services received in exchange for an award of equity or equity-based compensation based on the grant date fair value of the award. SFAS 123R also requires the measurement of liability awards under a share-based payment arrangement based on remeasurement of the award’s fair value at the conclusion of each quarterly reporting period until the date of settlement, taking into consideration the probability that the performance conditions will be satisfied.

Costs and Expenses.    The cost of products sold reported in the consolidated statements of operations represents the weighted average unit cost of propane, fuel oil and refined fuels, as well as the cost of natural gas and electricity sold, including transportation costs to deliver product from the Partnership’s supply points to storage or to the Partnership’s customer service centers. Cost of products sold also includes the cost of appliances, equipment and related parts sold or installed by the Partnership’s customer service centers computed on a basis that approximates the average cost of the products, as well as the mark-to-market (unrealized) gains or losses on ineffective portions of cash flow hedges used to hedge future purchases. Cost of products sold is reported exclusive of any depreciation and amortization as such amounts are reported separately within the consolidated statements of operations.

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

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

Net Income Per Unit.    Computations of earnings per Common Unit are performed in accordance with Emerging Issues Task Force (‘‘EITF’’) consensus 03-6 ‘‘Participating Securities and

F-13

---

Table of Contents

the Two-Class Method Under FAS 128’’ (‘‘EITF 03-6’’), when applicable. EITF 03-6 requires, among other things, the use of the two-class method of computing earnings per unit when participating securities exist. The two-class method is an earnings allocation formula that computes earnings per unit for Common Units and participating securities according to distributions declared and participation rights in undistributed earnings, as if all of the earnings were distributed to limited partners and the General Partner (inclusive of the previously outstanding IDRs of the General Partner which were considered participating securities under the two-class method).

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 loss per Common Unit for the year ended September 24, 2005. In addition, the application of EITF 03-6 did not have any impact on income per Common Unit for the year ended September 25, 2004. EITF 03-6 may have an impact on the computation of net income per Common Unit on a quarterly basis, depending on the level of net income in relation to distributions declared.

Basic income per Common Unit for the year ended September 30, 2006 is computed by dividing the limited partners’ share of net income, calculated under the two-class method of computing earnings, by the weighted average number of outstanding Common Units. Net income is allocated to the Unitholders and the General Partner in accordance with their respective partnership ownership interests, after giving effect to any priority income allocations to the General Partner for IDRs. Following the GP Exchange Transaction consummated on October 19, 2006, the two-class method of computing income per Common Unit under EITF 03-6 will no longer be applicable.

Basic net income (loss) per Common Unit for the years ended September 24, 2005 and September 25, 2004 is computed by dividing net income (loss), after deducting the General Partner’s interest, by the weighted average number of outstanding Common Units. Diluted net income (loss) per Common Unit for these same periods is computed by dividing net income (loss), after deducting the General Partner’s interest, by the weighted average number of outstanding Common Units and time vested restricted units granted under our 2000 Restricted Unit Plan. In computing diluted net income per Common Unit, weighted average units outstanding used to compute basic net income per Common Unit were increased by 143,039 and 105,711 units for the years ended September 30, 2006 and September 25, 2004, respectively, to reflect the potential dilutive effect of the time vested Restricted Units outstanding using the treasury stock method. Diluted net income per Common Unit for the year ended September 24, 2005 does not include 134,471 Restricted Units as their effect would be anti-dilutive.

Comprehensive Income.    The Partnership reports comprehensive (loss) income (the total of net income and all other non-owner changes in partners’ capital) within the consolidated statement of partners’ capital. Comprehensive (loss) income includes unrealized gains and losses on derivative instruments accounted for as cash flow hedges and minimum pension liability adjustments.

Recently Issued Accounting Standards.    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. SFAS 157 will be effective September 28, 2008, the beginning of the Partnership’s fiscal 2009. The Partnership is currently in the process of evaluating the impact that SFAS 157 may have on its consolidated financial position, results of operations and cash flows.

Also in September 2006, the FASB issued SFAS No. 158, ‘‘Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – An Amendment of FASB Statements No. 87, 88, 103 and 132R’’ (‘‘SFAS 158’’). SFAS 158 requires companies to recognize the funded status of pension and other postretirement benefit plans on sponsoring employers’ balance sheets and to recognize changes in the funded status in the year the changes occur. It also requires the measurement date of plan assets and obligations to occur at the end of the employers’ fiscal year. SFAS 158 is effective as of the end of the Partnership’s fiscal 2007. Based on the Partnership’s funded status and the consolidated balance sheet recognition as of September 30, 2006 (as disclosed in Note 12), adoption of SFAS 158 is not expected to have a significant impact on the Partnership’s consolidated financial

F-14

---

Table of Contents

position since the accrued pension liability already reflects the funded status of the defined benefit pension plan. Additionally, there would have been no impact to the Partnership’s consolidated statements of operations or cash flows for the year ended September 30, 2006. The actual impact from the adoption of SFAS 158 on the September 29, 2007 consolidated financial statements will differ due to changes in economic assumptions such as discount rates, measurement of fair values of plan assets and other possible changes in actuarial assumptions that may occur in connection with the upcoming fiscal 2007 measurement date.

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 is the beginning of the Partnership’s fiscal 2008. The Partnership is currently in the process of assessing the impact that FIN 48 will have on its consolidated financial statements and currently does not expect that adoption of FIN 48 will have a material impact on its financial position, results of operation or cash flows.

Reclassifications.    Certain prior period amounts have been reclassified to conform with the current period presentation.

3.	Acquisition of Agway Energy

On December 23, 2003, the Partnership acquired substantially all of the assets and operations of Agway Energy Products, LLC, Agway Energy Services, Inc. and Agway Energy Services PA, Inc. (collectively referred to as ‘‘Agway Energy’’) pursuant to an asset purchase agreement dated November 10, 2003 (the ‘‘Agway Acquisition’’). Agway Energy was a leading regional marketer of propane, fuel oil, gasoline and diesel fuel primarily in New York, Pennsylvania, New Jersey and Vermont. To complement its core marketing and delivery business, Agway Energy also installed and serviced a wide variety of home comfort equipment, particularly in the areas of HVAC. The Agway Acquisition was consistent with the Partnership’s business strategy of prudently pursuing acquisitions of retail propane distributors and other energy-related businesses that can complement or supplement its core propane operations. The Agway Acquisition also expanded the Partnership’s presence in the northeast energy market. The total cost of the Agway Acquisition, including the purchase price of $205,055 (net of a working capital adjustment paid to the Partnership of $945), $2,650 for non-compete agreements with certain members of the management of Agway Energy and $3,500 in transaction related costs, was approximately $211,205. The results of Agway Energy have been included in the Partnership’s consolidated financial statements from the date of the Agway Acquisition.

The following unaudited pro forma information presents the results of operations of the Partnership for the year ended September 25, 2004 as if the Agway Acquisition had occurred at the beginning of fiscal 2004. The pro forma information, however, is not necessarily indicative of the results of operations assuming the Agway Acquisition had occurred at the beginning of fiscal 2004, nor is it necessarily indicative of future results.

F-15

---

Table of Contents

			Year Ended September 25, 2004
As reported
Revenues				$	1,307,254
Income from continuing operations					28,944
Income from continuing operations per
Common Unit – basic				$	0.96
Pro Forma
Revenues				$	1,475,579
Income from continuing operations					33,235
Income from continuing operations per
Common Unit – basic				$	1.10

The as reported and pro forma income from continuing operations above includes the restructuring charge of $2,942 as further described in Note 7 below, the $5,337 non-cash pension settlement charge described in Note 12 below and the $3,177 non-cash charge for the impairment of goodwill described in Note 6 below.

4.	Distributions of Available Cash

The Partnership makes distributions to its partners approximately 45 days after the end of each fiscal quarter of the Partnership in an aggregate amount equal to its Available Cash for such quarter. Available Cash, as defined in the Partnership Agreement, generally means all cash on hand at the end of the respective fiscal quarter less the amount of cash reserves established by the Board of Supervisors in its reasonable discretion for future cash requirements. These reserves are retained for the proper conduct of the Partnership’s business, the payment of debt principal and interest and for distributions during the next four quarters. Prior to the consummation of the GP Exchange Transaction, distributions by the Partnership in an amount equal to 100% of its Available Cash were generally made 98.26% to the Common Unitholders and 1.74% to the General Partner, subject to the payment of incentive distributions to the General Partner to the extent the quarterly distributions exceeded a target distribution of $0.55 per Common Unit.

Prior to October 19, 2006, the General Partner had IDRs which represented an incentive for the General Partner to increase distributions to Common Unitholders in excess of the target quarterly distribution of $0.55 per Common Unit. With regard to the first $0.55 of quarterly distributions paid in any given quarter, 98.26% of the Available Cash was distributed to the Common Unitholders and 1.74% was distributed to the General Partner. With regard to the balance of quarterly distributions in excess of the $0.55 per Common Unit target distribution, 85% of the Available Cash was distributed to the Common Unitholders and 15% was distributed to the General Partner. As a result of the GP Exchange Transaction, the IDRs have been cancelled and the General Partner is no longer entitled to receive any cash distributions in respect of its general partner interests. Accordingly, beginning with the quarterly distribution paid on November 14, 2006 in respect of the fourth quarter of fiscal 2006, 100% of all cash distributions will be paid to the holders of Common Units.

The following summarizes the quarterly distributions per Common Unit declared and paid in respect of each of the quarters in the three fiscal years in the period ended September 30, 2006:

			Fiscal 2006						Fiscal 2005						Fiscal 2004
First Quarter				$	0.6125					$	0.6125					$	0.5875
Second Quarter					0.6125						0.6125						0.6000
Third Quarter					0.6375						0.6125						0.6125
Fourth Quarter					0.6625						0.6125						0.6125

On October 18, 2006, the Board of Supervisors declared a quarterly distribution of $0.6625 per Common Unit in respect of the fourth quarter of fiscal 2006, which was paid on November 14, 2006 to

F-16

---

Table of Contents

holders of record on November 7, 2006. There were no distributions paid to the General Partner in respect of the fourth quarter of fiscal 2006 other than as a holder of 784 Common Units.

5.	Selected Balance Sheet Information

Inventories consist of the following:

			As of
			September 30, 2006						September 24, 2005
Propane and refined fuels				$	72,143					$	66,383
Natural gas					1,148						3,267
Appliances and related parts					6,127						10,915
				$	79,418					$	80,565

During fiscal 2006, the Partnership recorded a charge of $3,517 to reduce the carrying value of appliance and parts inventory that will no longer be actively marketed by its customer service centers.

The Partnership enters into contracts to buy propane, fuel oil and natural gas for supply purposes. Such contracts generally have one year terms subject to annual renewal, with costs based on market prices at the date of delivery.

Property, plant and equipment consist of the following:

			As of
			September 30, 2006						September 24, 2005
Land and improvements				$	30,534					$	31,698
Buildings and improvements					75,535						76,746
Transportation equipment					37,125						40,257
Storage facilities					84,533						81,333
Equipment, primarily tanks and cylinders					447,573						436,918
Computer software					32,941						27,083
Construction in progress					7,973						9,954
					716,214						703,989
Less: accumulated depreciation					325,831						304,004
				$	390,383					$	399,985

Depreciation expense for the years ended September 30, 2006, September 24, 2005 and September 25, 2004 amounted to $30,564, $32,865 and $33,344, respectively. Depreciation expense for the years ended September 30, 2006 and September 24, 2005 included non-cash charges of $1,094 and $425, respectively, related to an impairment of assets as a result of restructuring activities in each of those years (see Note 7). Depreciation expense for the year ended September 25, 2004 included a non-cash charge of $1,000 related to a write-down of assets abandoned as a result of facility integration efforts in the Partnership’s northeast operations following the Agway Acquisition. As of September 30, 2006, the Partnership had approximately $4,308 of assets held for sale which were included in property, plant and equipment and are being actively marketed.

6.	Goodwill and Other Intangible Assets

The Partnership’s fiscal 2006 annual goodwill impairment review resulted in no adjustments to the carrying amount of goodwill. Based on the results of its fiscal 2005 annual goodwill impairment review, the Partnership recorded a non-cash charge of $656 for the impairment of goodwill associated with its HVAC segment for the year ended September 24, 2005. During fiscal 2004, as a result of continued losses in one of the Partnership’s reporting units acquired in fiscal 1999, the carrying value of goodwill associated with the reporting unit was considered to be fully impaired when applying the discounted

F-17

---

Table of Contents

cash flow valuation analysis. Accordingly, the Partnership recorded a non-cash charge of $3,177 within the consolidated statement of operations related to goodwill impairment for the year ended September 25, 2004.

The changes in the carrying amount of goodwill for the years ended September 30, 2006 and September 24, 2005 are as follows:

			Propane						Fuel Oil and Refined Fuels						Natural Gas and Electricity						HVAC						Total
Balance as of September 25, 2004				$	262,559					$	10,900					$	7,900					$	656					$	282,015
Goodwill impairment charge recognized					—						—						—						(656	)					(656	)
Balance as of September 24, 2005					262,559						10,900						7,900						—						281,359
Activity					—						—						—						—						—
Balance as of September 30, 2006				$	262,559					$	10,900					$	7,900					$	—					$	281,359

Other intangible assets, the majority of which were acquired in the Agway Acquisition, consist of the following:

			As of
			September 30, 2006						September 24, 2005
Customer lists				$	19,866					$	19,866
Tradenames					1,499						2,531
Non-compete agreements					986						4,956
Other					1,967						1,967
					24,318						29,320
Less: accumulated amortization					6,220						8,635
				$	18,098					$	20,685

Aggregate amortization expense related to other intangible assets for the years ended September 30, 2006, September 24, 2005 and September 25, 2004 was $2,587, $4,897 and $3,399, respectively. Amortization expense for the year ended September 24, 2005 included a non-cash charge of $810 attributable to an impairment in the value of tradenames associated with the HVAC segment which were acquired in the Agway Acquisition. Aggregate amortization expense related to other intangible assets for each of the five succeeding fiscal years as of September 30, 2006 is as follows: 2007 – $2,036; 2008 – $1,999; 2009 – $1,995; 2010 – $1965 and 2011 – $1,960.

7.	Restructuring Costs

During the fourth quarter of fiscal 2005 the Partnership approved and initiated a plan of reorganization to realign its field operations in an effort to streamline the operating footprint and leverage the system infrastructure to achieve additional operational efficiencies and reduce costs. As a result of this field realignment during the fourth quarter of fiscal 2005, the Partnership identified 85 positions which were eliminated under the plan. During fiscal 2006, the Partnership continued its efforts to streamline the operating footprint and identify operating efficiencies, including plans to restructure its HVAC service offerings. In this regard, during the third quarter of fiscal 2006 the Partnership eliminated nearly 200 positions, primarily service technicians and sales personnel, supporting its HVAC installation activities. The focus of the Partnership’s ongoing service offerings will be in support of its existing customer base within the propane, fuel oil and refined fuels and natural gas and electricity segments. As a result of this restructuring, as well as the additional steps taken during fiscal 2006 in relation to the field realignment, the Partnership has eliminated an additional 325 positions during fiscal 2006 bringing the total to more than 400 since the beginning of the fourth quarter of fiscal 2005. During fiscal 2006, the Partnership recorded additional severance charges of $5,276 associated with these activities. In addition, during fiscal 2006, the Partnership

F-18

---

Table of Contents

recorded a restructuring charge of $800 related to exit costs, primarily lease terminations costs, associated with a plan to exit certain activities of the HomeTown Hearth & Grill business included within the all other business segment.

For the year ended September 24, 2005, the Partnership recorded a restructuring charge of $2,775 related primarily to employee termination costs incurred as a result of actions taken during fiscal 2005, including for the 85 positions eliminated under the field realignment plan described above.

During fiscal 2004, in connection with the initial integration of certain management and back office functions of Agway Energy, the Partnership’s management approved and initiated plans to restructure the operations of both the Partnership and Agway Energy. Restructuring charges of $2,942 related to plans that had an impact on the assets, employees and operations of the Partnership were recorded in the statement of operations for fiscal 2004 when specific decisions were approved and costs associated with such activities were incurred. As of September 30, 2006, the majority of the activities associated with this restructuring plan were completed.

The components of remaining restructuring charges are as follows:

			Reserve at September 24, 2005						Charges Through September 30, 2006						Utilization Through September 30, 2006						Reserve at September 30, 2006
Charges expensed:
Severance and other employee costs				$	1,671					$	5,276					$	(5,326	)				$	1,621
Other exit costs					150						800						(96	)					854
Total				$	1,821					$	6,076					$	(5,422	)				$	2,475

The remaining $2,475 reserve for restructuring and other exit costs as of September 30, 2006 is expected to be paid over the course of the next twelve months.

8.	Income Taxes

For federal income tax purposes, as well as for state income tax purposes in the majority of the states in which the Partnership operates, the earnings attributable to the Partnership and the Operating Partnership are not subject to corporate level income tax. Rather, the taxable income or loss, which may vary substantially from the net income or net loss reported by the Partnership in the consolidated statement of operations, is includable in the federal and state income tax returns of the individual partners. The aggregate difference in the basis of the Partnership’s net assets for financial and tax reporting purposes cannot be readily determined as the Partnership does not have access to information regarding each partner’s tax attributes in the Partnership. The earnings of the Corporate Entities that do not qualify under the Internal Revenue Code for partnership status are subject to federal and state income taxes. The Partnership’s fuel oil and refined fuels, natural gas and electricity and HVAC business segments are structured as Corporate Entities and, as such, are subject to corporate level income tax.

The income tax provision (benefit) of the Partnership consists of the following:

			Year Ended
			September 30, 2006						September 24, 2005						September 25, 2004
Current
Federal				$	196					$	(6	)				$	(302	)
State and local					568						809						305
				$	764					$	803					$	3

The federal income tax benefits reported for fiscal 2005 and 2004 result from a refund of prior taxes paid.

F-19

---

Table of Contents

The provision for income taxes differs from income taxes computed at the United States federal statutory rate as a result of the following:

			Year Ended
			September 30, 2006						September 24, 2005						September 25, 2004
Income tax provision at federal statutory tax rate				$	31,759					$	(2,546	)				$	19,006
Impact of Partnership income not subject to federal income taxes					(28,411	)					(10,710	)					(27,477	)
Permanent differences					396						(1,632	)					1,135
Change in valuation allowance					(3,766	)					14,888						7,336
State income taxes					568						809						305
Alternative minimum tax					196						—						—
Other, net					22						(6	)					(302	)
Provision for income taxes				$	764					$	803					$	3

The components of net deferred taxes and the related valuation allowance using current enacted tax rates are as follows:

			As of
			September 30, 2006						September 24, 2005
Deferred tax assets:
Net operating loss carryforwards				$	42,031					$	45,524
Allowance for doubtful accounts					1,092						1,946
Inventory					713						531
Amortization of intangible assets					66						557
Depreciation					181						48
Deferred revenue					2,419						—
Derivative instruments					—						1,777
Severance and other exit costs					58						375
AMT credit carryforward					196						—
Other accruals					3,088						740
Total deferred tax assets					49,844						51,498
Deferred tax liabilities:
Derivative instruments					2,112						—
Total deferred tax liabilities					2,112						—
Net deferred tax assets					47,732						51,498
Valuation allowance					(47,732	)					(51,498	)
Net deferred tax assets				$	—					$	—

In order to fully realize the net deferred tax assets, the Corporate Entities will need to generate future taxable income. A valuation allowance is provided when it is more likely than not that some portion or all of the deferred tax assets will not be realized. Although certain Corporate Entities generated taxable income during fiscal 2006, based upon the level of current taxable income and projections of future taxable income of the Corporate Entities over the periods which deferred tax assets are expected to be deductible, management believes that it is more likely than not that the Partnership will not realize the full benefit of its deferred tax assets as of September 30, 2006 and September 24, 2005. Of the total valuation allowance as of September 30, 2006, $21,519 was established through purchase accounting for the Agway Acquisition in December 2003. To the extent that a reversal of a portion of the valuation allowance is warranted in the future, the reversal will be recorded as a reduction of goodwill with no impact on the deferred tax provision.

F-20

---

Table of Contents

As of September 30, 2006, the Partnership had tax loss carryforwards for federal income tax reporting purposes of approximately $113,305 which are available to offset future federal taxable income and expire between 2011 and 2026.

9.	Short-Term and Long-Term Borrowings

Short-term and long-term borrowings consist of the following:

			As of
			September 30, 2006						September 24, 2005
Senior Notes, 6.875%, due December 15, 2013, net of unamortized discount of $ 1,696 and $1,930, respectively				$	423,304					$	423,070
Term Loan, 6.29% to 7.16%, due March 31, 2010					125,000						125,000
Note payable, 8%, due in annual installments through 2006					—						475
Short-term borrowings under Revolving Credit Agreement					—						26,750
					548,304						575,295
Less: current portion					—						27,225
				$	548,304					$	548,070

On December 23, 2003, the Partnership and its subsidiary, Suburban Energy Finance Corporation, issued $175,000 aggregate principal amount of Senior Notes (the ‘‘2003 Senior Notes’’) with an annual interest rate of 6.875%. On March 31, 2005, the Partnership and Suburban Energy Finance Corporation issued $250,000 additional senior notes under the indenture governing the 2003 Senior Notes in order to refinance $340,000 of previously outstanding senior notes which required annual principal amortization of $42,500 through 2012 (the ‘‘Refinancing’’). The Partnership’s obligations under the 2003 Senior Notes are unsecured and rank senior in right of payment to any future subordinated indebtedness and equally in right of payment with any future senior indebtedness. The 2003 Senior Notes are structurally subordinated to, which means they rank effectively behind, any debt and other liabilities of the Operating Partnership. The 2003 Senior Notes mature on December 15, 2013, and require semi-annual interest payments in June and December. The Partnership is permitted to redeem some or all of the 2003 Senior Notes any time on or after December 15, 2008, at redemption prices specified in the indenture governing the 2003 Senior Notes. In addition, in the event of a change of control of the Partnership, as defined in the indenture governing the 2003 Senior Notes, the Partnership must offer to repurchase the notes at 101% of the principal amount repurchased, if the holders of the notes exercise the right of repurchase.

On October 20, 2004, the Operating Partnership executed the Third Amended and Restated Credit Agreement (the ‘‘Revolving Credit Agreement’’), replacing the Second Amended and Restated Credit Agreement which would have expired in May 2006. On March 31, 2005 in conjunction with the Refinancing, the Operating Partnership executed the first amendment to the Revolving Credit Agreement to provide, among other things, for a five-year $125,000 term loan facility due March 31, 2010 (the ‘‘Term Loan’’). The Revolving Credit Agreement, as amended, was scheduled to expire on October 20, 2008 and, in addition to the Term Loan, provided available credit of $150,000 in the form of a $75,000 revolving working capital facility and a separate $75,000 letter of credit facility. On August 26, 2005, the Partnership completed the second amendment to the Revolving Credit Agreement which, among other things, extended the maturity date to March 31, 2010 to coincide with the maturity of the Term Loan, eliminated the stand-alone $75,000 letter of credit facility and combined that facility with the existing revolving working capital facility and increased the available revolving borrowing capacity by an additional $25,000, thereby raising the amount of the working capital facility to $175,000 (including the $75,000 from the former stand-alone letter of credit facility). On February 23, 2006, the Partnership completed the third amendment to the Revolving Credit Agreement which authorized the Operating Partnership to incur additional indebtedness of up to $10,000 in connection with capital leases and up to $20,000 in short-term borrowings during the period

F-21

---

Table of Contents

from December 1 to April 1 in each fiscal year. The third amendment provides the Partnership with greater financial flexibility for general working capital purposes during periods of peak demand, if necessary.

Borrowings under the Revolving Credit Agreement, including the Term Loan, bear interest at a rate based upon either LIBOR or Wachovia National Bank’s prime rate, plus, in each case, the applicable margin or the Federal Funds rate plus 1/2 of 1%. An annual facility fee ranging from 0.375% to 0.50%, based upon certain financial tests, is payable quarterly whether or not borrowings occur. As of September 30, 2006, there were no borrowings outstanding under the working capital facility of the Revolving Credit Agreement. As of September 24, 2005, there was $26,750 outstanding under the working capital facility of the Revolving Credit Agreement that was used to fund working capital requirements.

In connection with the Term Loan, the Operating Partnership also entered into an interest rate swap contract with a notional amount of $125,000. Effective March 31, 2005 through March 31, 2010, the Operating Partnership will pay a fixed interest rate of 4.66% to the issuing lender on notional principal amount of $125,000, effectively fixing the LIBOR portion of the interest rate at 4.66%. In return, the issuing lender will pay to the Operating Partnership a floating rate, namely LIBOR, on the same notional principal amount. The applicable margin above LIBOR, as defined in the Revolving Credit Agreement, is not included in, and will be paid in addition to this fixed interest rate of 4.66%. The fair value of the interest rate swap amounted to $1,182 and ($1,293) at September 30, 2006 and September 24, 2005, respectively, and is included in other assets and other liabilities, respectively, with a corresponding amount included within OCI.

The Revolving Credit Agreement and the 2003 Senior Notes both contain various restrictive and affirmative covenants applicable to the Operating Partnership and the Partnership, respectively, including (i) restrictions on the incurrence of additional indebtedness, and (ii) restrictions on certain liens, investments, guarantees, loans, advances, payments, mergers, consolidations, distributions, sales of assets and other transactions. Under the Revolving Credit Agreement, the Operating Partnership is required to maintain a leverage ratio (the ratio of total debt to EBITDA) of less than 4.0 to 1. In addition, the Operating Partnership is required to maintain an interest coverage ratio (the ratio of EBITDA to interest expense) of greater than 2.5 to 1 at the Partnership level. The Partnership and the Operating Partnership were in compliance with all covenants and terms of the 2003 Senior Notes and the Revolving Credit Agreement as of September 30, 2006.

Debt origination costs representing the costs incurred in connection with the placement of, and the subsequent amendment to, the Partnership’s Senior Notes and Revolving Credit Agreement were capitalized within other assets and are being amortized on a straight-line basis over the term of the respective debt agreements. Other assets at September 30, 2006 and September 24, 2005 include debt origination costs with a net carrying amount of $7,557 and $8,848, respectively. Aggregate amortization expense related to deferred debt origination costs included within interest expense for the years ended September 30, 2006, September 24, 2005 and September 25, 2004 was $1,324, $1,514 and $1,421, respectively.

The aggregate amounts of long-term debt maturities subsequent to September 30, 2006 are as follows: 2007 – $0; 2008 – $0; 2009 – $0; 2010 – $125,000; and, thereafter – $423,304.

10.	Share-Based Compensation Arrangements

As described in Note 2, the Partnership accounts for its share-based compensation arrangements under SFAS 123R which requires the recognition of compensation cost over the respective service period for employee services received in exchange for an award of equity or equity-based compensation based on the grant date fair value of the award, as well as the measurement of liability awards under a share-based payment arrangement based on remeasurement of the award’s fair value at the conclusion of each quarterly reporting period until the date of settlement, taking into consideration the probability that the performance conditions will be satisfied. The Partnership has historically recognized unearned compensation associated with awards under its 2000 Restricted Unit Plan ratably to expense over the vesting period based on the fair value of the award on the grant date

F-22

---

Table of Contents

and has historically recognized compensation cost and the associated unearned compensation liability for equity-based awards under its Long-Term Incentive Plan consistent with the requirements of SFAS 123R.

2000 Restricted Unit Plan.    In November 2000, the Partnership adopted the Suburban Propane Partners, L.P. 2000 Restricted Unit Plan (the ‘‘2000 Restricted Unit Plan’’) which authorizes the issuance of Common Units to executives, managers and other employees and members of the Board of Supervisors of the Partnership. On October 17, 2006, the Partnership adopted amendments to the 2000 Restricted Unit Plan which, among other things, increased the number of Common Units authorized for issuance under the plan by 230,000 for a total of 717,805. Restricted Units issued under the 2000 Restricted Unit Plan vest over time with 25% of the Common Units vesting at the end of each of the third and fourth anniversaries of the grant date and the remaining 50% of the Common Units vesting at the end of the fifth anniversary of the grant date. The 2000 Restricted Unit Plan participants are not eligible to receive quarterly distributions or vote their respective Restricted Units until vested. Restrictions also limit the sale or transfer of the units during the restricted periods. The value of the Restricted Unit is established by the market price of the Common Unit on the date of grant. Restricted Units are subject to forfeiture in certain circumstances as defined in the 2000 Restricted Unit Plan. Compensation expense for the unvested awards is recognized ratably over the vesting periods and is net of estimated forfeitures.

Following is a summary of activity in the 2000 Restricted Unit Plan:

			Units						Weighted Average Grant Date Fair Value Per Unit
Outstanding September 27, 2003					150,548					$	25.37
Granted					115,730						30.64
Forfeited					(27,560	)					(25.46	)
Vested					(10,605	)					(20.66	)
Outstanding September 25, 2004					228,113					$	28.25
Granted					94,239						33.20
Forfeited					(26,282	)					(30.92	)
Vested					(22,292	)					(24.77	)
Outstanding September 24, 2005					273,778					$	29.17
Granted					120,365						26.51
Forfeited					(18,154	)					(30.04	)
Vested					(35,203	)					(24.85	)
Outstanding September 30, 2006					340,786					$	29.28

As of September 30, 2006, there was $4,766 of total unrecognized compensation cost related to unvested Common Units awarded under the 2000 Restricted Unit Plan. Compensation cost associated with the unvested awards is expected to be recognized over a weighted-average period of 1.9 years. Compensation expense for the 2000 Restricted Unit Plan for years ended September 30, 2006, September 24, 2005 and September 25, 2004 was $2,221, $1,806 and $1,171, respectively.

Long-Term Incentive Plan.   The Partnership has a non-qualified, unfunded long-term incentive plan for officers and key employees (‘‘LTIP-2’’) which provides for payment, in the form of cash, for an award of equity-based compensation at the end of a three-year performance period. The level of compensation earned under LTIP-2 is based on the market performance of the Partnership’s Common Units on the basis of total return to Unitholders (‘‘TRU’’) compared to the TRU of a predetermined peer group primarily composed of other Master Limited Partnerships, approved by the Compensation Committee of the Board of Supervisors, over the same three-year performance period. Compensation expense for the year ended September 30, 2006 was $1,249. As a result of the performance at the end of fiscal 2005, the Partnership recorded a reversal of compensation expense in the amount of ($644) for the year ended September 24, 2005.

F-23

---

Table of Contents

11.	Compensation Deferral Plan

In 1996, the Partnership adopted the 1996 Restricted Unit Award Plan (the ‘‘1996 Restricted Unit Plan’’) which authorized the issuance of Common Units with an aggregate value of $15,000 (731,707 Common Units valued at the initial public offering price of $20.50 per unit) to executives, managers and Elected Supervisors of the Partnership. According to the change of control provisions of the 1996 Restricted Unit Plan, all outstanding Restricted Units on the closing date of the Recapitalization in May 1999 vested and converted into Common Units. At the date of the Recapitalization, individuals who became members of the General Partner surrendered receipt of 553,896 Common Units, representing substantially all of their vested Restricted Units, in exchange for the right to participate in the Compensation Deferral Plan.

Effective May 26, 1999, in connection with the Partnership’s Recapitalization, the Partnership adopted the Compensation Deferral Plan (the ‘‘Deferral Plan’’) which provided for eligible employees of the Partnership to defer receipt of all or a portion of the vested Restricted Units granted under the 1996 Restricted Unit Plan in exchange for the right to participate in and receive certain payments under the Deferral Plan. Senior management of the Partnership surrendered 553,896 Common Units, at the date of the Recapitalization, into the Deferral Plan. The Partnership deposited into a trust on behalf of these individuals 553,896 Common Units. During fiscal 2000, certain members of management deferred receipt of an additional 42,925 Common Units granted under the Deferral Plan, with a fair value of $19.91 per Common Unit at the date of grant, by depositing the units into the trust.

In January 2003, in accordance with the terms of the Deferral Plan, 297,310 of the deferred units were distributed to certain members of the General Partner and became freely traded, while the remaining members of management elected to further defer receipt of their deferred units (totaling 299,511 Common Units) until a later date through January 2008. In November 2004, an additional 3,272 Common Units with a fair value of $109 were deposited into the Deferral Plan on behalf of individuals electing to defer receipt of Common Units vested under the 2000 Restricted Unit Plan. On November 2, 2005, the Deferral Plan was amended to disallow any additional deferrals of Common Units into the trust subsequent to December 31, 2004.

During fiscal 2006, 5,726 Common Units were distributed from the Deferral Plan, resulting in a reduction of $183 in the deferred compensation liability and a corresponding reduction in the value of Common Units held in trust, both within partners’ capital.

As of September 30, 2006 and September 24, 2005, there were 294,877 and 300,603 Common Units, respectively, held in trust under the Deferral Plan. The value of the Common Units deposited in the trust and the related deferred compensation liability in the amount of $5,704 and $5,887 as of September 30, 2006 and September 24, 2005, respectively, are reflected in the accompanying consolidated balance sheets as components of partners’ capital.

12. Employee Benefit Plans

Defined Contribution Plan.    The Partnership has an employee Retirement Savings and Investment Plan (the ‘‘401(k) Plan’’) covering most employees. Employer contributions and costs relating to the 401(k) Plan are a percent of the participating employees’ compensation, subject to the achievement of annual performance targets of the Partnership. These contributions totaled $3,868, $183 and $1,261 for the years ended September 30, 2006, September 24, 2005 and September 25, 2004, respectively.

Pension Benefits and Retiree Health and Life Benefits.

Pension Benefits.    The Partnership has a noncontributory defined benefit pension plan which was originally designed to cover all eligible employees of the Partnership who met certain requirements as to age and length of service. Effective January 1, 1998, the Partnership amended its noncontributory defined benefit pension plan to provide for a cash balance format as compared to a final average pay format which was in effect prior to January 1, 1998. The cash balance format is designed to evenly

F-24

---

Table of Contents

spread the growth of a participant’s earned retirement benefit throughout his/her career as compared to the final average pay format, under which a greater portion of employee benefits were earned toward the latter stages of one’s career. Effective January 1, 2000, participation in the noncontributory defined benefit pension plan was limited to eligible participants in existence on that date with no new participants eligible to participate in the plan. On September 20, 2002, the Board of Supervisors approved an amendment to the defined benefit pension plan whereby, effective January 1, 2003, future service credits ceased and eligible employees receive interest credits only toward their ultimate retirement benefit.

Contributions, as needed, are made to a trust maintained by the Partnership. The trust’s assets consist primarily of domestic and international mutual funds, as well as fixed income securities. Contributions to the defined benefit pension plan are made by the Partnership in accordance with the Employee Retirement Income Security Act of 1974 minimum funding standards plus additional amounts which may be determined from time to time. There were no minimum funding requirements for the defined benefit pension plan for fiscal 2006, 2005 or 2004. Recently, there has been increased scrutiny over cash balance defined benefit pension plans and resulting litigation regarding such plans sponsored by other companies. Partly in response to these developments, the federal Pension Protection Act of 2006 (the ‘‘2006 Pension Act’’) was recently enacted, and these developments may result in further legislative changes impacting cash balance defined benefit pension plans in the future. The Partnership is still evaluating the potential impact of the 2006 Pension Act on its defined benefit pension plan and there can be no assurances that the 2006 Pension Act and/or future legislative developments will not have an adverse effect on the Partnership’s results of operations or cash flows.

Retiree Health and Life Benefits.    The Partnership provides postretirement health care and life insurance benefits for certain retired employees. Partnership employees hired prior to July 1993 and that retired prior to March 1998 are eligible for such benefits if they reached a specified retirement age while working for the Partnership. Effective January 1, 2000, the Partnership terminated its postretirement benefit plan for all eligible employees retiring after March 1, 1998. All active and eligible employees who were to receive benefits under the postretirement plan subsequent to March 1, 1998, were provided a settlement by increasing their accumulated benefits under the cash balance pension plan noted above. The Partnership’s postretirement health care and life insurance benefit plans are unfunded. Effective January 1, 2006, the Partnership changed its postretirement health care plan from a self-insured program to one that is fully insured under which the Partnership pays a portion of the insurance premium on behalf of the eligible participants. This modification to the postretirement health care plan reduced the accumulated benefit obligation by $5,133 and resulted in a reduction of the net periodic postretirement benefit expense by approximately $637 for the year ended September 30, 2006.

F-25

---

Table of Contents

Projected Benefit Obligation, Fair Value of Plan Assets and Funded Status.    The following tables provide a reconciliation of the changes in the benefit obligations and the fair value of the plan assets for each of the years ended September 30, 2006 and September 24, 2005 and a statement of the funded status for both years using an end of year measurement date. Under the Partnership’s defined benefit pension plan the accumulated benefit obligation and the projected benefit obligation are the same.

			Pension Benefits												Retiree Health and Life Benefits
			2006						2005						2006						2005
Reconciliation of benefit obligations:
Benefit obligation at beginning of year				$	182,079					$	177,056					$	33,673					$	35,506
Service cost					—						—						15						18
Interest cost					9,146						9,107						1,416						1,783
Plan amendments					—						—						(5,133	)					—
Actuarial loss (gain)					2,157						12,025						(1,989	)					(1,377	)
Settlement payments					(11,521	)					(8,251	)					—						—
Benefits paid					(8,381	)					(7,858	)					(2,952	)					(2,257	)
Benefit obligation at end of year				$	173,480					$	182,079					$	25,030					$	33,673
Reconciliation of fair value of plan assets:
Fair value of plan assets at beginning of year				$	141,873					$	142,021					$	—					$	—
Actual return on plan assets					10,423						15,961						—						—
Employer contributions					10,000						—						2,952						2,257
Settlement payments					(11,521	)					(8,251	)					—						—
Benefits paid					(8,381	)					(7,858	)					(2,952	)					(2,257	)
Fair value of plan assets at end of year				$	142,394					$	141,873					$	—					$	—
Funded status:
Funded status at end of year				$	(31,086	)				$	(40,206	)				$	(25,030	)				$	(33,673	)
Unrecognized prior service cost					—						—						(4,915	)					(865	)
Net unrecognized actuarial loss (gain)					66,778						75,656						(720	)					1,269
Net amount recognized at end of year				$	35,692					$	35,450					$	(30,665	)				$	(33,269	)
Amounts recognized in consolidated balance
sheets consist of:
Prepaid benefit cost				$	—					$	—					$	—					$	—
Accrued benefit liability					(31,086	)					(40,206	)					(30,665	)					(33,269	)
Accumulated other comprehensive (loss)					66,778						75,656						—						—
Net amount recognized at end of year				$	35,692					$	35,450						(30,665	)					(33,269	)
Less: Current portion																	2,906						2,211
Non-current benefit liability																$	(27,759	)				$	(31,058	)

During fiscal 2006, lump sum benefit payments to either terminated or retired individuals amounted to $11,521. The lump sum benefit payments exceeded the interest cost component of the net periodic pension cost of $9,147 and, as a result, the Partnership was required to recognize a non-cash settlement charge of $4,437 during the fourth quarter of fiscal 2006, pursuant to SFAS No. 88 ‘‘Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits’’. The non-cash charge was required to accelerate recognition of a portion of cumulative unrecognized losses in the defined benefit pension plan. These unrecognized losses are accumulated as a reduction to partners’ capital (cumulative reduction of $75,657 as of the end of the 2005 fiscal year) and are being amortized to expense as part of the Partnership’s net periodic pension

F-26

---

Table of Contents

cost in accordance with SFAS No. 87 ‘‘Employers’ Accounting for Pensions’’. A similar non-cash settlement charge of $5,337 was recorded in fiscal 2004 as a result of the level of lump sum benefit payments.

The Partnership made voluntary contributions of $10,000 and $15,100 to the defined benefit pension plan during fiscal 2006 and 2004, respectively, thereby taking proactive steps to improve the funded status of the plan and reduce the minimum pension liability.

Plan Asset Allocation.    The following table presents the actual allocation of assets held in trust:

			September 30, 2006						September 24, 2005
Common stock					39	%					42	%
Mutual funds					50	%					55	%
Cash and cash equivalents					11	%					3	%
					100	%					100	%

The Partnership’s investment policies and strategies, as set forth in the Investment Management Policy and Guidelines, are monitored by a Benefits Committee comprised of seven members of management. The investment objective related to the defined benefit pension plan assets is to maximize total return with strong emphasis on the preservation of capital. The target asset mix is as follows: (i) the domestic equity portfolio should range between 30% and 50%; (ii) the international equity portfolio should range between 10% and 25%; and, (iii) the fixed income portion of the portfolio should range between 25% and 50%.

Projected Contributions and Benefit Payments.    There are no projected minimum funding requirements under the Partnership’s defined benefit pension plan for fiscal 2007. The Partnership estimates that retiree health and life benefit contributions will be $2,163 for fiscal 2007. Estimated future benefit payments for both pension and retiree health and life benefits are as follows:

Fiscal Year			Pension Benefits						Retiree Health and Life Benefits
2007				$	21,585					$	2,163
2008					14,275						2,109
2009					14,917						2,056
2010					14,452						1,993
2011					13,819						1,931
2012 through 2016					66,855						8,312

Effect on Operations.    The following table provides the components of net periodic benefit costs included in operating expenses for the years ended September 30, 2006, September 24, 2005 and September 25, 2004:

			Pension Benefits																		Retiree Health and Life Benefits
			2006						2005						2004						2006						2005						2004
Service cost				$	—					$	—					$	—					$	15					$	18					$	18
Interest cost					9,147						9,107						9,765						1,416						1,783						2,138
Expected return on plan assets					(10,295	)					(9,335	)					(9,848	)					—						—						—
Amortization of prior service cost					—						—						—						(1,083	)					(720	)					(720	)
Settlement charge					4,437						—						5,337						—						—						—
Recognized net actuarial loss					6,469						6,641						5,986						—						—						—
Net periodic benefit costs				$	9,758					$	6,413					$	11,240					$	348					$	1,081					$	1,436

F-27

---

Table of Contents

Actuarial Assumptions.    The assumptions used in the measurement of the Partnership’s benefit obligations as of September 30, 2006 and September 24, 2005 are shown in the following table:

			Pension Benefits												Retiree Health and Life Benefits
			2006						2005						2006						2005
Weighted-average discount rate					5.50	%					5.25	%					5.50	%					5.25	%
Average rate of compensation increase					n/a						n/a						n/a						n/a

The assumptions used in the measurement of periodic pension and postretirement benefit costs for the years ended September 30, 2006, September 24, 2005 and September 25, 2004 are shown in the following table:

			Pension Benefits																		Retiree Health and Life Benefits
			2006						2005						2004						2006						2005						2004
Weighted-average discount rate					5.25	%					5.50	%					6.00	%					5.25	%					5.25	%					6.00	%
Average rate of compensation increase					n/a						n/a						n/a						n/a						n/a						n/a
Weighted-average expected long- term rate of return on plan assets					8.00	%					7.50	%					7.75	%					n/a						n/a						n/a
Health care cost trend					n/a						n/a						n/a						10.00	%					11.00	%					11.50	%

The discount rate assumption takes into consideration current market expectations related to long-term interest rates and the projected duration of the Partnership’s pension obligations based on a benchmark index with similar characteristics as the expected cash flow requirements of the Partnership’s defined benefit pension plan over the long-term. The long-term rate of return on plan assets assumption reflects estimated future performance in the Partnership’s pension asset portfolio considering the investment mix of the pension asset portfolio and historical asset performance.

The 10.00% increase in health care costs assumed at September 30, 2006 is assumed to decrease gradually to 5.00% in fiscal 2013 and to remain at that level thereafter. Increasing the assumed health care cost trend rates by 1.0% in each year would increase the Partnership’s benefit obligation as of September 30, 2006 by approximately $512 and the aggregate of service and interest components of net periodic postretirement benefit expense for the year ended September 30, 2006 by approximately $51. Decreasing the assumed health care cost trend rates by 1.0% in each year would decrease the Partnership’s benefit obligation as of September 30, 2006 by approximately $464 and the aggregate of service and interest components of net periodic postretirement benefit expense for the year ended September 30, 2006 by approximately $45. The Partnership has concluded that the prescription drug benefits within the retiree medical plan will not qualify for a Medicare subsidy available under recent legislation.

13.	Financial Instruments

Derivative Instruments and Hedging Activities.    The Partnership purchases propane and refined fuels at various prices that are eventually sold to its customers, exposing the Partnership to market fluctuations in the price of these commodities. A control environment has been established which includes policies and procedures for risk assessment and the approval, reporting and monitoring of derivative instruments and hedging activities. The Partnership closely monitors the potential impacts of commodity price changes and, where appropriate, utilizes commodity futures, forward and option contracts to hedge its commodity price risk, to protect margins and to ensure supply during periods of high demand. Derivative instruments are used to hedge a portion of the Partnership’s forecasted purchases for no more than one year in the future. At September 30, 2006, the fair value of derivative instruments described above resulted in derivative assets (unrealized gains) of $9,642 included within prepaid expenses and other current assets and derivative liabilities (unrealized losses) of $2,537 included within other current liabilities. As of September 30, 2006, unrealized losses on derivative instruments designated as cash flow hedges in the amount of $1,884 were included in OCI and are expected to be recognized in earnings during the next 12 months as the hedged forecasted transactions occur. However, due to the volatility of the commodities market, the corresponding value in OCI is subject to change prior to its impact on earnings.

F-28

---

Table of Contents

Unrealized (non-cash) gains and losses attributable to the mark-to-market on derivative instruments for all periods presented are reported within cost of products sold. For the years ended September 30, 2006, September 24, 2005 and September 25, 2004, cost of products sold included unrealized gains (losses) in the amount of $14,472, ($2,497) and ($4,523), respectively, attributable to changes in the fair value of derivative instruments not designated as hedges. In connection with the Agway Acquisition, the Partnership acquired certain futures and option contracts that were identified as hedges of future purchases of fuel oil and propane with a fair value of $6,327 which were recorded as derivative assets at fair value in purchase accounting. As the underlying futures and option contracts were settled during fiscal 2004, the derivative assets were charged to cost of products sold as an offset to the realized gains from contract settlement. The impact on cost of products sold represented a non-cash charge resulting from the application of purchase accounting on derivative instruments acquired. For the year ended September 25, 2004, the Partnership recorded a non-cash charge of $6,327 within cost of products sold related to contracts settled during the period.

As of September 30, 2006, an unrealized gain of $1,182 was included in OCI attributable to the Partnership’s interest rate swap agreement and is expected to be recognized in earnings as the interest on the Term Loan impacts earnings through March 31, 2010. However, due to changes in the interest rate environment, the corresponding value in OCI is subject to change prior to its impact on earnings.

Credit Risk.    The Partnership’s principal customers are residential and commercial end users of propane and fuel oil and refined fuels served by more than 300 locations in 30 states. No single customer accounted for more than 10% of revenues during fiscal 2006, 2005 or 2004 and no concentration of receivables exists as of September 30, 2006 or September 24, 2005.

Futures contracts are traded on and guaranteed by the New York Mercantile Exchange (the ‘‘NYMEX’’) and as a result, have minimal credit risk. Futures contracts traded with brokers of the NYMEX require daily cash settlements in margin accounts. The Partnership is subject to credit risk with forward and option contracts entered into with various third parties to the extent the counterparties do not perform. The Partnership evaluates the financial condition of each counterparty with which it conducts business and establishes credit limits to reduce exposure to credit risk based on non-performance. The Partnership does not require collateral to support the contracts.

Fair Value of Financial Instruments.    The fair value of cash and cash equivalents is not materially different from their carrying amounts because of the short-term nature of these instruments. The fair value of the Revolving Credit Agreement approximates the carrying value since the interest rates are periodically adjusted to reflect market conditions. Based on the current rates offered to the Partnership for debt of the same remaining maturities, the carrying value of the Partnership’s 2003 Senior Notes approximates their fair market value.

14. Commitments and Contingencies

Commitments.    The Partnership leases certain property, plant and equipment, including portions of the Partnership’s vehicle fleet, for various periods under noncancelable leases. Rental expense under operating leases was $27,217, $28,559 and $27,315 for the years ended September 30, 2006, September 24, 2005 and September 25, 2004, respectively.

Future minimum rental commitments under noncancelable operating lease agreements as of September 30, 2006 are as follows:

Fiscal Year
2006				$	17,280
2007					11,450
2008					7,865
2009					5,258
2010 and thereafter					4,996

Contingencies.

Self Insurance.    As discussed in Note 2, the Partnership is self-insured for general and product, workers’ compensation and automobile liabilities up to predetermined amounts above which third

F-29

---

Table of Contents

party insurance applies. At September 30, 2006 and September 24, 2005, the Partnership had accrued insurance liabilities of $45,413 and $46,457, respectively, representing the total estimated losses under these self-insurance programs. The Partnership is also involved in various legal actions which have arisen in the normal course of business, including those relating to commercial transactions and product liability. Management believes, based on the advice of legal counsel, that the ultimate resolution of these matters will not have a material adverse effect on the Partnership’s financial position or future results of operations, after considering its self-insurance liability for known and unasserted self-insurance claims. For the portion of the estimated self-insurance liability that exceeds insurance deductibles, the Partnership records an asset within other assets related to the amount of the liability expected to be covered by insurance which amounted to $8,665 and $10,046 as of September 30, 2006 and September 24, 2005, respectively.

Environmental.    The Partnership is subject to various federal, state and local environmental, health and safety laws and regulations. Generally, these laws impose limitations on the discharge of pollutants and establish standards for the handling of solid and hazardous wastes. These laws include the Resource Conservation and Recovery Act, the Comprehensive Environmental Response, Compensation and Liability Act (‘‘CERCLA’’), the Clean Air Act, the Occupational Safety and Health Act, the Emergency Planning and Community Right to Know Act, the Clean Water Act and comparable state statutes. CERCLA, also known as the ‘‘Superfund’’ law, imposes joint and several liability without regard to fault or the legality of the original conduct on certain classes of persons that are considered to have contributed to the release or threatened release of a ‘‘hazardous substance’’ into the environment. Propane is not a hazardous substance within the meaning of CERCLA. However, the Partnership owns real property where such hazardous substances may exist.

The Partnership is also subject to various laws and governmental regulations concerning environmental matters and expects that it will be required to expend funds to participate in the remediation of certain sites, including sites where it has been designated by the Environmental Protection Agency as a potentially responsible party under CERCLA and at sites with aboveground and underground fuel storage tanks.

With the Agway Acquisition, the Partnership acquired certain surplus properties with either known or probable environmental exposure, some of which are currently in varying stages of investigation, remediation or monitoring. Additionally, the Partnership identified that certain active sites acquired contained environmental conditions which may require further investigation, future remediation or ongoing monitoring activities. The environmental exposures include instances of soil and/or groundwater contamination associated with the handling and storage of fuel oil, gasoline and diesel fuel. Under the agreement for the Agway Acquisition, the seller was required to deposit $15,000 from the total purchase price into an escrow account to reimburse the Partnership for any such future environmental costs and expenses. The escrowed funds were to be used to fund such environmental costs and expenses during the first three years following the closing date of the Agway Acquisition.

Since the Agway Acquisition and through February 2006, $10,128 of the escrowed funds were utilized to fund environmental remediation expenditures. On March 17, 2006, the Partnership finalized an agreement with the seller for the release of the remaining escrowed funds to the Partnership and, as such, received $4,884 which will be used by the Partnership to fund its estimated future remediation and monitoring costs. Based on management’s estimate of required future remediation and monitoring activities, the remaining funds are expected to be sufficient to cover future requirements after considering expected reimbursement from state environmental agencies. As of September 30, 2006 and September 24, 2005, the environmental reserve amounted to $4,786 and $5,768, respectively, and the corresponding asset for expected reimbursements amounted to $1,294 and $6,151, respectively.

Estimating the extent of the Partnership’s responsibility at a particular site, and the method and ultimate cost of remediation of that site, requires making numerous assumptions. As a result, the ultimate cost to remediate any site may differ from current estimates, and will depend, in part, on whether there is additional contamination, not currently known to the Partnership, at that site. However, management believes that the Partnership’s past experience provides a reasonable basis for

F-30

---

Table of Contents

estimating these liabilities. As additional information becomes available, estimates are adjusted as necessary. While management does not anticipate that any such adjustment would be material to the Partnership’s financial statements, the result of ongoing or future environmental studies or other factors could alter this expectation and require recording additional liabilities. Management currently cannot determine whether the Partnership will incur additional liabilities or the extent or amount of any such liabilities.

Future developments, such as stricter environmental, health or safety laws and regulations thereunder, could affect the Partnership’s operations. Management does not anticipate that the cost of the Partnership’s compliance with environmental, health and safety laws and regulations, including CERCLA, as currently in effect and applicable to known sites will have a material adverse effect on the Partnership’s financial condition or results of operations. To the extent there are any environmental liabilities presently unknown to the Partnership or environmental, health or safety laws or regulations are made more stringent, however, there can be no assurance that the Partnership’s financial condition or results of operations will not be materially and adversely affected.

Legal Matters.    Following our Operating Partnership’s 1999 acquisition of the propane assets of SCANA Corporation (‘‘SCANA’’), Heritage Propane Partners, L.P. had brought an action against SCANA for breach of contract and fraud and against the Operating Partnership for tortious interference with contract and tortious interference with prospective contract. On October 21, 2004, the jury returned a unanimous verdict in favor of the Operating Partnership on all claims, but against SCANA. After the jury returned the verdict against SCANA, the Operating Partnership filed a cross-claim against SCANA for indemnification, seeking to recover defense costs. On November 2, 2006, subsequent to the end of fiscal 2006, SCANA and the Operating Partnership reached a settlement agreement wherein the Operating Partnership received $2,000 as a reimbursement of defense costs incurred as a result of the lawsuit. This amount will be recorded during the first quarter of fiscal 2007.

15.	Guarantees

The Partnership has residual value guarantees associated with certain of its operating leases, related primarily to transportation equipment, with remaining lease periods scheduled to expire periodically through fiscal 2013. Upon completion of the lease period, the Partnership guarantees that the fair value of the equipment will equal or exceed the guaranteed amount, or the Partnership will pay the lessor the difference. Although the fair value of equipment at the end of its lease term has historically exceeded the guaranteed amounts, the maximum potential amount of aggregate future payments the Partnership could be required to make under these leasing arrangements, assuming the equipment is deemed worthless at the end of the lease term, is approximately $17,166. Of this amount, the fair value of residual value guarantees for operating leases entered into after December 31, 2002 was $8,320 and $6,292 as of September 30, 2006 and September 24, 2005, respectively, which is reflected in other liabilities, with a corresponding amount included within other assets, in the accompanying consolidated balance sheets.

16.	Public Offerings

On December 16, 2003, the Partnership sold 2,600,000 Common Units in a public offering at a price of $30.90 per Common Unit realizing proceeds of $76,026, net of underwriting commissions and other offering expenses. On December 23, 2003, following the underwriters’ full exercise of their over-allotment option, the Partnership sold an additional 390,000 Common Units at $30.90 per Common Unit, generating additional net proceeds of $11,540. The aggregate net proceeds of $87,566 were used to fund a portion of the purchase price for the Agway Acquisition.

17.	Discontinued Operations and Disposition

The Partnership continuously evaluates its existing operations to identify opportunities to optimize the return on assets employed and selectively divests operations in slower growing or non-strategic markets and seeks to reinvest in markets that are considered to present more

F-31

---

Table of Contents

opportunities for growth. In line with that strategy, during fiscal 2004, the Partnership sold 24 customer service centers for net cash proceeds of $39,352. The Partnership recorded a gain on sale of $26,332 during fiscal 2004 which was accounted for within discontinued operations in accordance with SFAS No. 144, ‘‘Accounting for the Impairment or Disposal of Long-Lived Assets’’. During fiscal 2005, the Partnership finalized certain purchase price adjustments with the buyer of these customer service centers and recorded an additional gain on sale of $976. The individual captions on the consolidated statements of operations for the year ended September 25, 2004 exclude the results from these discontinued operations, which were part of the Partnership’s propane segment.

18.	Segment Information

The Partnership manages and evaluates its operations in five reportable segments: Propane, Fuel Oil and Refined Fuels, Natural Gas and Electricity, HVAC and All Other. The chief operating decision maker evaluates performance of the operating segments using a number of performance measures, including gross margins and operating profit. Costs excluded from these profit measures are captured in Corporate and include corporate overhead expenses not allocated to the operating segments. Unallocated corporate overhead expenses include all costs of back office support functions that are reported as general and administrative expenses within the consolidated statements of operations. In addition, certain costs associated with field operations support that are reported in operating expenses within the consolidated statements of operations, including purchasing, training and safety, are not allocated to the individual operating segments. Thus, operating profit for each operating segment includes only the costs that are directly attributable to the operations of the individual segment. The accounting policies of the operating segments are the same as those described in the summary of significant accounting policies in Note 2.

The propane segment is primarily engaged in the retail distribution of propane to residential, commercial, industrial and agricultural customers and, to a lesser extent, wholesale distribution to large industrial end users. In the residential and commercial markets, propane is used primarily for space heating, water heating, cooking and clothes drying. Industrial customers use propane generally as a motor fuel burned in internal combustion engines that power over-the-road vehicles, forklifts and stationary engines, to fire furnaces and as a cutting gas. In the agricultural markets, propane is primarily used for tobacco curing, crop drying, poultry brooding and weed control.

The fuel oil and refined fuels segment is primarily engaged in the retail distribution of fuel oil, kerosene, diesel and gasoline to residential and commercial customers for use primarily as a source of heat in homes and buildings.

The natural gas and electricity segment is engaged in the marketing of natural gas and electricity to residential and commercial customers in the deregulated energy markets of New York and Pennsylvania. Under this operating segment, the Partnership owns the relationship with the end consumer and has agreements with the local distribution companies to deliver the natural gas or electricity from the Partnership’s suppliers to the customer.

The HVAC segment is engaged in the sale, installation and servicing of a wide variety of home comfort equipment and parts, particularly in the areas of heating, ventilation and air conditioning.

Activities from the Partnership’s HomeTown Hearth & Grill and Suburban Franchising subsidiaries comprise the all other business segment.

F-32

---

Table of Contents

The following table presents certain data by reportable segment and provides a reconciliation of total operating segment information to the corresponding consolidated amounts for the periods presented:

			Year Ended
			September 30, 2006						September 24, 2005						September 25, 2004
Revenues:
Propane				$	1,086,083					$	969,943					$	856,109
Fuel oil and refined fuels					356,531						431,223						281,682
Natural gas and electricity					122,071						102,803						68,452
HVAC					87,258						106,115						92,072
All other					9,697						10,150						8,939
Total revenues				$	1,661,640					$	1,620,234					$	1,307,254
Income (loss) before interest expense, loss on debt
extinguishment and provision for income taxes:
Propane				$	186,144					$	147,468					$	143,933
Fuel oil and refined fuels					36,727						(6,474	)					14,911
Natural gas and electricity					11,297						6,463						4,154
HVAC					(14,837	)					(12,423	)					(2,686	)
All other					(5,321	)					(3,802	)					(8,125	)
Corporate					(81,826	)					(62,865	)					(82,408	)
Total income before interest expense, loss on debt extinguishment and provision for income taxes					132,184						68,367						69,779
Reconciliation to income (loss) from continuing operations
Interest expense, net					40,680						40,374						40,832
Loss on debt extinguishment					—						36,242						—
Provision for income taxes					764						803						3
Income (loss) from continuing operations				$	90,740					$	(9,052	)				$	28,944
Depreciation and amortization:
Propane				$	20,706					$	25,393					$	26,347
Fuel oil and refined fuels					4,351						4,802						4,302
Natural gas and electricity					849						967						555
HVAC					710						1,509						640
All other					1,160						281						343
Corporate					5,375						4,810						4,556
Total depreciation and amortization				$	33,151					$	37,762					$	36,743
			As of
			September 30, 2006						September 24, 2005
Assets
Propane				$	732,784					$	735,094
Fuel oil and refined fuels					92,173						124,232
Natural gas and electricity					22,644						30,294
HVAC					8,353						15,590
All other					2,719						4,990
Corporate					183,194						143,378
Eliminations					(87,981	)					(87,981	)
Total assets				$	953,886					$	965,597

F-33

---

Table of Contents

For the year ended September 30, 2006, income (loss) before interest expense, loss on debt extinguishment and provision for income taxes for the propane, fuel oil and refined fuels, HVAC and all other segments included restructuring charges of $2,802, $500, $1,854 and $920, respectively. In addition, depreciation and amortization expense for the propane and all other segments for the year ended September 30, 2006 reflected non-cash charges of $187 and $907, respectively, for the impairment of fixed assets (see Note 5).

For the year ended September 24, 2005, income (loss) before interest expense, loss on debt extinguishment and provision for income taxes for the propane, fuel oil and refined fuels and HVAC segments included $2,525, $125 and $125, respectively, for restructuring charges (see Note 7); and for the HVAC segment included the non-cash charge of $656 for goodwill impairment (see Note 6). In addition, depreciation and amortization expense for the HVAC segment for the year ended September 24, 2005 reflected the non-cash charge of $810 for the impairment of other intangible assets (see Note 6).

For the year ended September 25, 2004, income (loss) before interest expense, loss on debt extinguishment and provision for income taxes for the propane segment included restructuring charges of $2,942; and for the all other segment included the $3,177 non-cash charge for goodwill impairment (see Note 6).

19.	Subsequent Events

On October 19, 2006, following approval by the requisite vote of the Common Unitholders of the Partnership at its 2006 Tri-Annual Meeting held on October 17, 2006, the Partnership consummated an agreement with its General Partner for the acquisition of the General Partner’s IDRs, as well as its general partnership interests in both the Partnership and the Operating Partnership, in exchange for 2,300,000 newly issued Common Units. Pursuant to a Distribution, Release and Lockup Agreement by and among the Partnership, the Operating Partnership, the General Partner and the members of the General Partner, the Common Units were distributed to the members of the General Partner in exchange for their membership interests in the General Partner. The Common Units issued in the GP Exchange Transaction represent approximately 7% of the total number of Common Units outstanding after consummation of the GP Exchange Transaction.

Suburban Energy Services Group LLC will remain the general partner of both the Partnership and the Operating Partnership with no economic interest in future cash distributions (other than as a holder of 784 Common Units received in the GP Exchange Transaction and not distributed to its members), and the Chief Executive Officer of the Partnership will be the sole member of the General Partner. Initially the GP Exchange Transaction will result in an increase to the Partnership’s total annual cash distributions by $2,575, at the most recent annualized rate of $2.65 per Common Unit. With the elimination of the General Partner’s IDRs, which previously provided the General Partner with a 15% share of all future distribution increases, all future distribution increases will inure to the benefit of the Common Unitholders.

F-34

---

INDEX TO FINANCIAL STATEMENT SCHEDULE

SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES

						Page
Schedule II			Valuation and Qualifying Accounts – Years Ended September 30, 2006, September 24, 2005 and September 25, 2004			S-2

S-1

---

Table of Contents

SCHEDULE II

SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES

VALUATION AND QUALIFYING ACCOUNTS
(in thousands)

			Balance at Beginning of Period						Charged to Costs and Expenses						Other Additions						Deductions						Balance at End of Period
Year Ended September 25, 2004 (a)
Allowance for doubtful accounts				$	2,519					$	9,128					$	2,966					$	(6,717	)				$	7,896
Year Ended September 24, 2005
Allowance for doubtful accounts				$	7,896					$	9,289					$	—					$	(7,220	)				$	9,965
Year Ended September 30, 2006
Allowance for doubtful accounts				$	9,965					$	6,801					$	—					$	(11,236	)				$	5,530

(a)	Other additions for the year ended September 25, 2004 reflects allowances for doubtful accounts associated with the acquisition of Agway Energy.

S-2

---