SUBURBAN PROPANE PARTNERS LP - Quarter Report: 2006 June (Form 10-Q)

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 that began on June 15, 2004. The Partnership is permitted to redeem some or all of the 2003 Senior Notes any time on or after December 15, 2008, at redemption prices specified in the indenture governing the 2003 Senior Notes. In addition, in the event of a change of control of the Partnership, as defined in the indenture governing the 2003 Senior Notes, the Partnership must offer to repurchase the 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 Operating Partnership executed the second amendment to the Revolving Credit Agreement which, among other things, extended the maturity date of the working capital facility 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 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. On February 23, 2006, the Operating Partnership executed 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 from December 1 to April 1 in each fiscal year. The third amendment provides the Operating 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. 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 June 24, 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 with the issuing lender. Effective March 31, 2005 through March 31, 2010, the Operating Partnership will pay a fixed interest rate of 4.66% to the issuing lender on the 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 $4,016 and ($1,293) at June 24, 2006 and September 24, 2005, respectively, 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 of less than 4.0 to 1. In addition, the Operating Partnership is required to maintain an interest coverage ratio of greater than 2.5 to 1 on a consolidated basis. The

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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 June 24, 2006.

Debt origination costs representing the costs incurred in connection with the placement of, and the subsequent amendment to, the 2003 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 June 24, 2006 and September 24, 2005 include debt origination costs with a net carrying amount of $7,889 and $8,848, respectively. Aggregate amortization expense related to deferred debt origination costs included within interest expense for the three and nine months ended June 24, 2006 was $332 and $992, respectively, and $347 and $1,171 for the three and nine months ended June 25, 2005, respectively.

8.	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 (‘‘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. Distributions by the Partnership in an amount equal to 100% of its Available Cash will generally be 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 exceed a target distribution of $0.55 per Common Unit.

As defined in the Partnership Agreement, the General Partner holds IDRs which represent an incentive for the General Partner to increase distributions to Common Unitholders in excess of the target quarterly distribution of $0.55 per Common Unit. With regard to the first $0.55 per Common Unit of quarterly distributions paid in any given quarter, 98.26% of the Available Cash is distributed to the Common Unitholders and 1.74% is distributed to the General Partner. With regard to the balance of quarterly distributions in excess of the $0.55 per Common Unit target distribution, approximately 85% of the Available Cash is distributed to the Common Unitholders and approximately 15% is distributed to the General Partner. The quarterly cash distribution paid on May 9, 2006 also included a $258 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.

If the Proposed Exchange is completed, all IDRs will be cancelled and the General Partner will not be entitled to receive any cash distributions in respect of its general partner interests; accordingly, all cash distributions will be paid in respect of the Common Units (see Note 16).

On July 20, 2006, the Partnership announced a quarterly distribution of $0.6375 per Common Unit, or $2.55 on an annualized basis, in respect of the third quarter of fiscal 2006 payable on August 8, 2006 to holders of record on August 1, 2006. This quarterly distribution included the increase of $0.025 per Common Unit, or $0.10 per Common Unit on an annualized basis, previously announced on May 4, 2006. Additionally, on July 28, 2006, the Partnership announced a further increase in its quarterly distribution from $0.6375 to $0.6625 per Common Unit. This increase equates to $0.10 per Common Unit on an annualized basis to $2.65 per Common Unit. The quarterly distribution at this increased level will be payable in respect of the fourth quarter of fiscal 2006 on November 14, 2006 to Common Unitholders of record on November 7, 2006.

9.	Share-Based Compensation Arrangements

In December 2004, the Financial Accounting Standards Board (‘‘FASB’’) issued a revised SFAS No. 123, ‘‘Share Based Payments’’ (‘‘SFAS 123R’’) which was adopted by the Partnership effective for the first quarter of fiscal 2006 ended December 24, 2005. SFAS 123R is a revision of SFAS No. 123

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‘‘Accounting for Stock-Based Compensation’’ and supersedes APB Opinion No. 25 ‘‘Accounting for Stock Issued to Employees’’. 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. 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. 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. The Partnership 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. Accordingly, adoption of SFAS 123R did not have an impact on the Partnership’s consolidated financial position, results of operations or cash flows. Under the transition guidance provided in SFAS 123R, however, all unearned compensation as of the beginning of fiscal 2006 has been eliminated from the consolidated statement of partners’ capital with a corresponding reduction in partners’ capital — Common Unitholders resulting in no net impact to the Partnership’s financial position.

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 with an aggregate value of $10,000 (487,805 Common Units valued at the initial public offering price of $20.50 per unit) to executives, managers and other employees and members of the Board of Supervisors of the Partnership. Restricted Units issued under the 2000 Restricted Unit Plan vest over time with 25% of the Common Units vesting at the end of each of the third and fourth anniversaries of the 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.

During fiscal 2006, the Partnership awarded 120,365 Restricted Units under the 2000 Restricted Unit Plan at an aggregate grant date fair value of $3,191. Following is a summary of activity in the 2000 Restricted Unit Plan during fiscal 2006:

			Units						Weighted Average Grant Date Fair Value Per Unit
Outstanding September 24, 2005					273,778					$	29.17
Awarded					120,365						26.51
Forfeited					(17,029	)					30.19
Issued					(35,203	)					(24.85	)
Outstanding June 24, 2006					341,911					$	28.84

As of June 24, 2006, there was $5,384 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 2.7 years. Compensation expense for the 2000 Restricted Unit Plan for the three and nine months ended June 24, 2006 was $472 and $1,648, respectively, and $516 and $1,433 for the three and nine months ended June 25, 2005, 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

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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. As a result of the quarterly remeasurement of the liability for awards under LTIP-2, compensation expense for the three and nine months ended June 24, 2006 was $1,423 and $837, respectively. Compensation expense for the three and nine months ended June 25, 2005 was $239 and $857, respectively.

10.	Commitments and Contingencies

The Partnership is self-insured for general and product, workers’ compensation and automobile liabilities up to predetermined thresholds above which third party insurance applies. As of June 24, 2006 and September 24, 2005, the Partnership had accrued insurance liabilities of $47,918 and $46,457, respectively, representing the total estimated losses under these self-insurance programs. 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 $8,700 and $10,046 as of June 24, 2006 and September 24, 2005, respectively. The Partnership is also involved in various legal actions that 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.

The Partnership is subject to various laws and governmental regulations concerning environmental matters and expects that it will be required to expend funds to participate in remediation of these matters. 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. Subject to amounts withheld with respect to any pending claims made prior to such third anniversary, any remaining escrowed funds would be remitted to the sellers at the end of the three-year period.

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 June 24, 2006 and September 24, 2005, the Partnership had accrued environmental liabilities of $5,524 and $5,768, respectively, 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, the Partnership records an asset within other assets related to the amount of the liability expected to be reimbursed by state agencies, which amounted to $1,613 as of June 24, 2006.

The reserve estimates are based on the Partnership’s best estimate of future costs for environmental investigations, remediation and ongoing monitoring activities for properties with either known or probable environmental exposures. Estimating the extent of the Partnership’s responsibility for a

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particular site and the method and ultimate cost of remediation of that site requires a number of assumptions and estimates on the part of management. As a result, the ultimate outcome of remediation of the sites may differ from current estimates. As additional information becomes available, estimates will be adjusted as necessary. Based on information currently available, and taking into consideration the level of the environmental reserve, management believes that any liability that may ultimately result from changes in current estimates will not have a material impact on the results of operations, financial position or cash flows of the Partnership.

11.	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 equipments’ fair value at the end of their lease terms 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 $19,467. 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 June 24, 2006 and September 24, 2005, respectively, which is reflected in other liabilities, with a corresponding amount included within other assets, in the accompanying condensed consolidated balance sheets.

12.	Pension Plans and Other Postretirement Benefits

The following table provides the components of net periodic benefit costs for the three and nine months ended June 24, 2006 and June 25, 2005:

			Pension Benefits												Postretirement Benefits
			Three Months Ended												Three Months Ended
			June 24, 2006						June 25, 2005						June 24, 2006						June 25, 2005
Service cost				$	—					$	—					$	4					$	4
Interest cost					2,287						2,277						422						446
Expected return on plan assets					(2,565	)					(2,334	)					—						—
Amortization of prior service costs					—						—						(180	)					(180	)
Recognized net actuarial loss					1,617						1,660						—						—
Net periodic benefit cost				$	1,339					$	1,603					$	246					$	270

			Pension Benefits												Postretirement Benefits
			Nine Months Ended												Nine Months Ended
			June 24, 2006						June 25, 2005						June 24, 2006						June 25, 2005
Service cost				$	—					$	—					$	12					$	12
Interest cost					6,861						6,831						1,266						1,338
Expected return on plan assets					(7,695	)					(7,002	)					—						—
Amortization of prior service costs					—						—						(540	)					(540	)
Recognized net actuarial loss					4,851						4,980						—						—
Net periodic benefit cost				$	4,017					$	4,809					$	738					$	810

There are no projected minimum employer contribution requirements under Internal Revenue Service Regulations for fiscal 2006 under our defined benefit pension plan. The projected annual contribution requirements related to the Partnership’s postretirement health care and life insurance benefit plan for fiscal 2006 is $3,000, of which $1,982 has been contributed during the nine months ended June 24, 2006.

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13.	Discontinued Operations

During the second quarter of fiscal 2005, the Partnership finalized certain purchase price adjustments with the buyer of ten customer service centers completed in fiscal 2004, as part of the Partnership’s strategy of divesting operations in slower growing or non-strategic markets. These adjustments resulted in an additional gain of $976 which was reported within discontinued operations for the nine months ended June 25, 2005.

14.	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 in the consolidated statements of operations. In addition, certain costs associated with field operations support that are reported in operating expenses in the consolidated statements of operations, 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 Note in the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 24, 2005.

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

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

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

The HVAC segment is engaged in the sale, installation and servicing of a wide variety of home comfort equipment and parts, particularly in the areas of heating, ventilation and air conditioning. In furtherance of the Partnership’s efforts to restructure its field operations and to focus on is core operating segments, the Partnership initiated plans to streamline the HVAC service offerings by significantly reducing installation activities and focusing on service offerings that support the Partnership’s existing customer base within its propane, refined fuels and natural gas and electricity segments.

The all other business segment includes activities from the HomeTown Hearth & Grill and Suburban Franchising subsidiaries.

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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:

			Three Months Ended												Nine Months Ended
			June 24, 2006						June 25, 2005						June 24, 2006						June 25, 2005
Revenues:
Propane				$	198,505					$	194,662					$	895,407					$	814,275
Fuel oil and refined fuels					66,540						86,485						305,412						352,708
Natural gas and electricity					19,662						20,178						103,716						81,931
HVAC					16,540						22,727						70,183						82,001
All other					2,751						3,128						7,686						7,680
Total revenues				$	303,998					$	327,180					$	1,382,404					$	1,338,595
(Loss) income before interest expense, loss on debt extinguishment and income taxes:
Propane				$	22,291					$	8,460					$	165,358					$	138,386
Fuel oil and refined fuels					195						(3,222	)					36,116						1,889
Natural gas and electricity					2,325						857						10,486						5,772
HVAC					(6,617	)					(5,668	)					(9,402	)					(9,356	)
All other					(866	)					(698	)					(3,558	)					(3,049	)
Corporate					(17,994	)					(13,318	)					(55,683	)					(37,308	)
Total (loss) income before interest expense, loss on debt extinguishment and income taxes					(666	)					(13,589	)					143,317						96,334
Reconciliation to (loss) income from continuing operations:
Loss on debt extinguishment					—						36,242						—						36,242
Interest expense, net					9,686						9,943						31,192						30,286
Provision for income taxes					121						138						354						336
(Loss) income from continuing operations				$	(10,473	)				$	(59,912	)				$	111,771					$	29,470
Depreciation and amortization:
Propane				$	5,084					$	6,304					$	15,656					$	19,083
Fuel oil and refined fuels					1,043						1,195						3,259						3,556
Natural gas and electricity					221						183						625						785
HVAC					138						170						420						529
All other					31						65						1,050						215
Corporate					1,239						1,279						3,855						3,345
Total depreciation and amortization				$	7,756					$	9,196					$	24,865					$	27,513

			As of
			June 24, 2006						September 24, 2005
Assets:
Propane				$	730,448					$	735,094
Fuel oil and refined fuels					105,727						124,232
Natural gas and electricity					23,529						30,294
HVAC					11,519						15,590
All other					4,204						4,990
Corporate					168,196						143,378
Eliminations					(87,981	)					(87,981	)
Total assets				$	955,642					$	965,597

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As a result of the Partnership’s field realignment efforts which began during the fourth quarter of fiscal 2005 (see Note 3), included within segment (loss) income before interest expense, loss on debt extinguishment and income taxes are restructuring charges of $1,443, $1,250 and $237 in the Propane, HVAC and All Other segments, respectively, for the three months ended June 24, 2006 and $2,072, $500, $1,250 and $605 included in the Propane, Fuel Oil and Refined Fuels, HVAC and All Other segments, respectively, for the nine months ended June 24, 2006. In addition, depreciation and amortization expense for the Propane and All Other segments for the nine months ended June 24, 2006 reflects non-cash charges of $227 and $907, respectively, for the impairment of fixed assets (see Note 2).

15.	Recently Issued Accounting Pronouncements

In February 2006, the FASB issued SFAS No. 155, ‘‘Accounting for Certain Hybrid Financial Instruments — an amendment of FASB Statements No. 133 and 140’’ (‘‘SFAS 155’’). Among other things, SFAS 155 permits the fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation under SFAS 133. It also clarifies which interest-only strips and principal-only strips are not subject to the requirements of SFAS 133 and establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation. SFAS 155 is effective for all financial instruments acquired, issued, or subject to a remeasurement event occurring after the Partnership’s fiscal year ending September 30, 2006. The Partnership is currently evaluating the provisions of SFAS 155 and currently believes that adoption will not have a material effect on its financial position, results of operations or cash flows.

In March 2005, the FASB issued FASB Interpretation No. 47, ‘‘Accounting for Conditional Asset Retirement Obligations’’ (‘‘FIN 47’’). FIN 47 clarifies the term ‘‘conditional asset retirement obligation’’ as a legal obligation to retire an asset when the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. FIN 47 also requires an entity to recognize a liability for the fair value of the conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. FIN 47 is effective no later than the end of the Partnership’s fiscal year ending September 30, 2006. The Partnership is currently evaluating the provisions of FIN 47 and currently believes that adoption will not have a material effect on its financial position, results of operations or cash flows.

16.	Subsequent Event

On July 28, 2006, the Partnership announced that it had entered into an agreement with its General Partner (which is majority-owned by members of the Partnership’s senior management) pursuant to which the Partnership will issue 2,300,000 new Common Units to the General Partner in exchange for the cancellation of the General Partner’s IDRs, the economic interest in the Partnership included in the general partner interest therein and the economic interest in the Operating Partnership included in the general partner interest therein. The Common Units to be issued in the Proposed Exchange will represent approximately 7% of the total number of Common Units to be outstanding after giving effect to the Proposed Exchange. Following consummation of the Proposed Exchange, the General Partner will remain the general partner of the Partnership and the Operating Partnership but its general partner interests will have no economic interest in future cash distributions. Consummation of the Proposed Exchange is subject to certain customary conditions, including approval by the Common Unitholders of both the Proposed Exchange and certain amendments to the Partnership Agreement necessary to effect the Proposed Exchange. Initially the Proposed Exchange will result in an increase to the Partnership’s total annual cash distributions by $2,575, at the most recent increased annualized rate of $2.65 per Common Unit.

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ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following is a discussion of the financial condition and results of operations of the Partnership as of and for the three and nine months ended June 24, 2006. The discussion should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations and the historical consolidated financial statements and notes thereto included in the Annual Report on Form 10-K for the fiscal year ended September 24, 2005.

Factors that Affect Our Operating Results and Financial Condition

Product Costs

The level of profitability in the retail propane, fuel oil, natural gas and electricity businesses is largely dependent on the difference between retail sales price and product cost. The unit cost of our products, particularly propane, 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 period to period as product costs fluctuate with propane, fuel oil, crude oil and natural gas commodity market conditions. In addition, in periods of sustained higher commodity prices, as was experienced in fiscal 2005 and into the first three quarters of fiscal 2006, retail sales volumes may be negatively impacted by customer conservation efforts.

Seasonality

The retail propane and fuel oil distribution businesses, as well as the natural gas marketing business, are seasonal because of the primary use for heating in residential and commercial buildings. Historically, approximately two-thirds of our retail propane volume is sold during the six-month peak heating season from October through March. The fuel oil business tends to experience greater seasonality given its more limited use for space heating and approximately three-fourths of our fuel oil volumes are sold between October and March. Consequently, sales and operating profits are concentrated in our first and second fiscal quarters. Cash flows from operations, therefore, are greatest during the second and third fiscal quarters when customers pay for product purchased during the winter heating season. We expect lower operating profits and either net losses or lower net income during the period from April through September (our third and fourth fiscal quarters). To the extent necessary, we will reserve cash from the second and third quarters for distribution to holders of our Partnership interests in the first and fourth fiscal quarters.

Weather

Weather conditions have a significant impact on the demand for our products, in particular propane, fuel oil and natural gas, for both heating and agricultural purposes. Many of our customers rely heavily on propane, fuel oil or natural gas as a heating source. Accordingly, the volume sold is directly affected by the severity of the winter weather in our service areas, which can vary substantially from year to year. In any given area, sustained warmer than normal temperatures will tend to result in reduced propane, fuel oil and natural gas consumption, while sustained colder than normal temperatures will tend to result in greater use.

Risk Management

Product supply contracts are generally one-year agreements subject to annual renewal and generally permit suppliers to charge posted market prices (plus transportation costs) at the time of delivery or the current prices established at major delivery points. Since rapid increases in the cost of

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propane or fuel oil may not be immediately passed on to retail customers, such increases could reduce profitability. During fiscal 2005, approximately 70% of our fuel oil volumes were sold to individual customers under agreements pre-establishing a maximum price per gallon over a twelve-month period (the ‘‘Ceiling Program’’). While our strategy was to enter into derivative instruments in the form of futures and options traded on the New York Mercantile Exchange (‘‘NYMEX’’) covering a majority of the fuel oil we expected to sell to customers under the Ceiling Program in an effort to protect the margins under the program, we evaluated the costs of such hedge protection and elected not to hedge deliveries in February through April of 2005 (impacting our second and third fiscal quarters of fiscal 2005) under this program. After evaluating the costs to adequately hedge the Ceiling Program in the current fuel oil price environment, we decided to discontinue offering the Ceiling Program after the fiscal 2005 heating season. Accordingly, we have not offered the Ceiling Program in fiscal 2006.

We engage in risk management activities to reduce the effect of price volatility on our product costs and to help ensure the availability of product during periods of short supply. We are currently a party to propane and fuel oil futures contracts traded on the NYMEX and enter into forward and option agreements with third parties to purchase and sell propane at fixed prices in the future. Risk management activities are monitored by an internal Commodity Risk Management Committee, made up of five members of management, through enforcement of our Hedging and Risk Management Policy and reported to our Audit Committee. Risk management transactions may not always result in increased product margins. See the additional discussion in Item 3 of this Quarterly 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 of the Annual Report on Form 10-K for the most recent fiscal year ended September 24, 2005.

Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated, requiring management to make certain assumptions with respect to values or conditions that cannot be known with certainty at the time the financial statements are prepared. The preparation of financial statements in conformity with generally accepted accounting principles (‘‘GAAP’’) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We are also subject to risks and uncertainties that may cause actual results to differ from estimated results. Estimates are used when accounting for depreciation and amortization of long-lived assets, employee benefit plans, self-insurance and legal reserves, environmental reserves, allowances for doubtful accounts, asset valuation assessments, tax valuation allowances 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

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periods and therefore, generally affect our recognized expense and recorded obligation in such future periods. While we believe that our assumptions are appropriate, significant differences in our actual experience or significant changes in market conditions may materially affect our pension and other postretirement obligations and our future expense. See the Liquidity and Capital Resources section of Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations in the Annual Report on Form 10-K for the year ended September 24, 2005 for additional disclosure regarding pension benefits.

Self-Insurance Reserves.    Our accrued insurance reserves represent the estimated costs of known and anticipated or unasserted claims under our general and product, workers’ compensation and automobile insurance policies. Accrued insurance provisions for unasserted claims arising from unreported incidents are based on an analysis of historical claims data. For each claim, we record a self-insurance provision up to the estimated amount of the probable claim utilizing actuarially determined loss development factors applied to actual claims data. Our self-insurance provisions are susceptible to change to the extent that actual claims development differs from historical claims development. We maintain insurance coverage wherein our net exposure for insured claims is limited to the insurance deductible, claims above which are paid by our insurance carriers. For the portion of our estimated self-insurance liability that exceeds our deductibles, we record an asset for the amount of the liability expected to be covered by insurance.

Environmental Reserves.    We establish reserves for environmental exposures when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated based upon our 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 has been agreed and we are reasonably assured of receiving such contribution or reimbursement. Environmental reserves are not discounted.

Goodwill Impairment Assessment.    We assess the carrying value of goodwill at a reporting unit level, at least annually, based on an estimate of the fair value of the respective reporting unit. Fair value of the reporting unit is estimated using discounted cash flow analyses taking into consideration estimated cash flows in a ten-year projection period and a terminal value calculation at the end of the projection period.

Derivative Instruments and Hedging Activities.    See Item 3 of this Quarterly Report for additional information about accounting for derivative instruments and hedging activities.

Executive Overview of Results of Operations and Financial Condition

The positive momentum from the first six months of fiscal 2006 continued throughout the third quarter, reflecting the positive steps taken over the past twelve months to further focus on the areas of our business that are within our control, primarily our cost structure, customer mix and operating efficiencies. These steps include our decision to eliminate the fuel oil Ceiling Program for fiscal 2006, the field realignment process that continues to drive operating efficiencies and cost savings and our continued efforts to improve our customer mix by exiting certain lower margin business in the propane and refined fuels segments. As a result, we reported a significant improvement in earnings for our third quarter ended June 24, 2006 with a seasonal net loss of $10.5 million, or $0.33 per Common Unit, an improvement of $49.4 million (82.5%) compared to a net loss of $59.9 million, or $1.92 per Common Unit, in the prior year quarter. Net loss for the fiscal 2005 third quarter included a one-time charge of $36.2 million to reflect the loss on debt extinguishment associated with our March 31, 2005 debt refinancing. EBITDA (as defined and reconciled below) of $7.1 million for the three months ended June 24, 2006 increased $11.5 million compared to an Adjusted EBITDA loss (which excludes the $36.2 million loss on debt extinguishment as defined and reconciled below) of $4.4 million in the prior year quarter. EBITDA for the fiscal 2006 third quarter included a $2.9 million restructuring charge attributable primarily to the realignment of our field operations, as well as a charge of

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$0.8 million within cost of products sold to reduce the carrying value of inventory that will no longer be actively marketed by our customer service centers as a result of the reorganization of our HVAC segment discussed below.

One of the contributing factors to our increased earnings compared to the prior year quarter was the residual benefit from the decision to eliminate the fuel oil Ceiling Program following the fiscal 2005 heating season. During the second and third quarters of the prior year, 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 the prior year third quarter was approximately $10.0 million. By eliminating this pricing program for 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 in our field operations without significant customer losses.

With our field realignment initiatives which began during the fourth quarter of fiscal 2005, we have significantly restructured our operating footprint and have realized cost savings through the achievement of operating efficiencies and better use of technology. In furtherance of our efforts to streamline our field operations and to focus on our core operating segments, during the third quarter of fiscal 2006 we initiated plans to restructure our HVAC service offerings and eliminated nearly 200 positions supporting our HVAC installation activities. The focus of our ongoing service offerings will be in support of our existing customer base within our propane, refined fuels and natural gas and electricity segments. These activities, coupled with the nearly 150 positions and 530 vehicles eliminated through the second quarter of fiscal 2006, have resulted in significant savings in our fixed cost structure. During the third quarter of fiscal 2006, we continued to realize a significant portion of the anticipated cost savings and efficiencies from the field realignment efforts as combined operating and general and administrative expenses of $102.0 million decreased $9.6 million, or 8.6%, compared to the prior year quarter. This decline in operating and general and administrative expenses was achieved despite a $2.6 million increase in variable compensation costs in line with the higher earnings.

These significantly increased earnings were achieved despite the negative effect on volumes from the continued high energy price environment resulting in customer conservation. Retail propane gallons sold in the third quarter of fiscal 2006 decreased 9.3 million gallons, or 9.5%, to 88.7 million gallons compared to 98.0 million gallons in the prior year quarter. Sales of fuel oil and other refined fuels decreased 21.9 million gallons, or 45.2%, to 26.6 million gallons during the third quarter of fiscal 2006 compared to 48.5 million gallons in the prior year quarter. The decrease in sales volumes is attributable to customer conservation and, to a significant extent, our continued efforts to strategically exit certain lower margin commercial, industrial and agricultural businesses in both our propane and refined fuels segments. Specifically, in the propane segment, we have 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 5.3 million gallons during the third quarter of fiscal 2006 compared to the prior year quarter. In the fuel oil and refined fuels segment, our decision to exit certain lower margin diesel and gasoline business has resulted in a decrease in volumes sold of approximately 14.8 million gallons during the three months ended June 24, 2006 compared to the prior year quarter.

Looking ahead to the remainder of fiscal 2006, we expect that our operating results will continue to be positively impacted by the cost savings and efficiencies achieved to date, as well as further efficiencies anticipated from our field realignment efforts. Our field realignment efforts will continue into the fourth quarter of fiscal 2006 as we focus on further streamlining the operations ahead of the fiscal 2007 heating season. With the positive steps to date and our continued focus on the areas within our control, we expect an improvement in operating results in the fourth quarter of fiscal 2006 compared to the prior year fourth quarter and we believe we are well positioned for supporting the growth of our core operating segments.

From a cash flow perspective, as anticipated we made use of the working capital facility of our Revolving Credit Agreement throughout the fiscal 2006 heating season to fund seasonal working

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capital needs, particularly in light of the high commodity price environment. During the third quarter of fiscal 2006, we fully repaid all outstanding borrowings under the working capital facility and ended the quarter with approximately $37.9 million in cash on hand, which exceeded the ending cash balance at the end of June of the prior year by $26.7 million. Our cash flow from operations improved $98.6 million to $120.9 million through the first nine months of fiscal 2006. Our anticipated cash requirements for the remainder of fiscal 2006 include: (i) maintenance and growth capital expenditures of approximately $9.7 million; (ii) interest payments of approximately $4.3 million; and (iii) distributions of approximately $20.1 million to Common Unitholders and the General Partner reflecting our quarterly distribution at the increased rate of $0.6375 per Common Unit payable on August 8, 2006. In addition, on the strength of these earnings, our Board of Supervisors declared the eleventh increase in our quarterly distribution from $0.6375 to $0.6625 per Common Unit. This increase equates to $0.10 per Common Unit annualized to $2.65 per Common Unit. The quarterly distribution at this increased level will be payable in respect of the fourth quarter of fiscal 2006 on November 14, 2006 to Common Unitholders of record on November 7, 2006. Based on our current estimates of cash flow from operations, our cash position at the end of the third quarter of fiscal 2006 and availability under the Revolving Credit Agreement (unused borrowing capacity under the working capital facility of $125.7 million after considering outstanding letters of credit of $49.3 million as of June 24, 2006), we expect to have sufficient funds to meet our current and future obligations.

On July 28, 2006, we announced that the Partnership entered into an agreement for the acquisition of our General Partner’s incentive distribution rights (‘‘IDRs’’), as well as the economic interests in its general partnership interests in both us and our operating partnership, in exchange for 2,300,000 newly issued Common Units (the ‘‘Proposed Exchange’’). The terms of the Proposed Exchange were established through an arm’s length negotiation between the Audit Committee of our Board of Supervisors and the General Partner. In the negotiation, the Audit Committee was assisted by an independent financial advisor.

The Proposed Exchange is intended to simplify our capital structure and lower its future cost of capital. If the Proposed Exchange is completed, all IDRs will be cancelled and the General Partner will not be entitled to receive any cash distributions in respect of its general partner interests. Accordingly, 100% of all future distribution increases, if any, will inure to the benefit of the Common Unitholders. In addition, as a result of the Proposed Exchange, the interests of senior management in the Partnership will be entirely in the form of Common Units, further aligning the interests of management with those of the Common Unitholders. Consummation of the Proposed Exchange is subject to certain customary conditions, including the approval of the Proposed Exchange by our Common Unitholders at our Tri-Annual Meeting, which is expected to be held during the fourth calendar quarter of 2006.

Results of Operations

Three Months Ended June 24, 2006 Compared to Three Months Ended June 25, 2005

Revenues

(Dollars in thousands)			Three Months Ended												Increase (Decrease)						Percent Increase (Decrease)
			June 24, 2006						June 25, 2005
Revenues
Propane				$	198,505					$	194,662					$	3,843				2.0%
Fuel oil and refined fuels					66,540						86,485						(19,945	)			(23.1%)
Natural gas and electricity					19,662						20,178						(516	)			(2.6%)
HVAC					16,540						22,727						(6,187	)			(27.2%)
All other					2,751						3,128						(377	)			(12.1%)
Total revenues				$	303,998					$	327,180					$	(23,182	)			(7.1%)

Total revenues decreased $23.2 million, or 7.1%, to $304.0 million for the three months ended June 24, 2006 compared to $327.2 million for the three months ended June 25, 2005, driven primarily by lower volumes in our propane and fuel oil and refined fuels segments, offset to an extent by higher average selling prices resulting from significantly higher commodity prices. In the commodities

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markets, the average price of propane and fuel oil continued to increase and remained significantly above historical levels during the three months ended June 24, 2006, thus continuing to negatively impact volumes as a result of customer conservation, yet increasing average selling prices.

Revenues from the distribution of propane and related activities of $198.5 million in the third quarter of fiscal 2006 increased $3.8 million, or 2.0%, compared to $194.7 million in the prior year quarter, 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 the third quarter of fiscal 2006 decreased 9.3 million gallons, or 9.5%, to 88.7 million gallons from 98.0 million gallons in the prior year quarter. Propane volumes sold were negatively affected by customer conservation efforts and our effort to focus on higher margin residential customers. In several markets, we elected to exit certain lower margin commercial, industrial and agricultural customers, thus reducing our reported volume yet improving our overall profitability with an improved customer mix. Average propane selling prices in the third quarter of fiscal 2006 increased 18.6% over the prior year quarter as a result of higher commodity prices for propane. The average posted price of propane during the third quarter of fiscal 2006 increased approximately 28% compared to the average posted prices in the prior year quarter. Additionally, included within the propane segment are revenues from wholesale and risk management activities of $6.8 million for the three months ended June 24, 2006 which decreased $9.5 million compared to the prior year quarter.

Revenues from the distribution of fuel oil and other refined fuels of $66.5 million in the third quarter of fiscal 2006 decreased $19.9 million, or 23.1%, from $86.5 million in the prior year quarter. Sales of fuel oil and other refined fuels amounted to 26.6 million gallons during the third quarter of fiscal 2006 compared to 48.5 million gallons in the prior year quarter, a decrease of 21.9 million gallons, or 45.2%. 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 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. By eliminating the Ceiling Program for fiscal 2006, we have been successful in implementing our market-based pricing strategies in our field operations without significant customer losses, which has resulted in an improvement in our margin opportunities and, therefore, in our profitability within this segment. Average selling prices in our fuel oil and refined fuels segment increased 40.4% as a result of higher fuel oil commodity prices, coupled with the decreased emphasis on lower priced diesel and gasoline businesses. The average posted price of fuel oil during the third quarter of fiscal 2006 increased approximately 31% compared to the average posted prices in the prior year quarter.

Revenues for the third quarter of fiscal 2006 were unfavorably impacted by a 2.6% decrease in our natural gas and electricity marketing segment, which decreased to $19.7 million from $20.2 million in the prior year quarter as a result of a decline in electricity volumes, partially offset by an increase in the average selling price for natural gas. HVAC revenues declined 27.2%, to $16.5 million during the third quarter of fiscal 2006 compared to $22.7 million in the prior year quarter, primarily as a result of our decision to eliminate certain HVAC installation activities described in more detail below.

Cost of Products Sold

(Dollars in thousands)			Three Months Ended												Decrease						Percent Decrease
			June 24, 2006						June 25, 2005
Cost of products sold
Propane				$	110,083					$	112,547					$	(2,464	)			(2.2%)
Fuel oil and refined fuels					56,923						78,757						(21,834	)			(27.7%)
Natural gas and electricity					15,900						17,770						(1,870	)			(10.5%)
HVAC					7,538						9,100						(1,562	)			(17.2%)
All other					1,573						1,752						(179	)			(10.2%)
Total cost of products sold				$	192,017					$	219,926					$	(27,909	)			(12.7%)
As a percent of total revenues					63.2	%					67.2	%

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The cost of products sold reported in the condensed 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 condensed consolidated statements of operations.

Cost of products sold decreased $27.9 million, or 12.7%, to $192.0 million for the three months ended June 24, 2006 compared to $219.9 million in the prior year quarter. The decrease results primarily from the lower sales volumes described above, offset to an extent by higher commodity prices for all products. Cost of products sold in the fiscal 2006 third quarter include a $1.0 million unrealized (non-cash) gain representing the net change in the fair value of derivative instruments during the period, compared to a $2.3 million unrealized gain in the prior year quarter resulting in a $1.3 million increase in cost of products sold for the quarter ended June 24, 2006 compared to the prior year quarter (see Item 3 in this Quarterly 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 $110.1 million decreased $2.5 million, or 2.2%, compared to the prior year quarter. Higher propane prices resulted in an $18.0 million increase in cost of products sold during the third quarter of fiscal 2006 compared to the prior year quarter, partially offset by decreased propane volumes which had an impact of $9.1 million. Lower wholesale and risk management activities, noted above, decreased cost of products sold by $11.8 million compared to the prior year quarter.

Cost of products sold associated with our fuel oil and refined fuels segment of $56.9 million decreased $21.8 million, or 27.7%, compared to the prior year quarter. Lower sales volumes resulted in a $35.6 million decrease in cost of products sold during the third quarter of fiscal 2006 compared to the prior year quarter, partially offset by higher commodity prices which had an impact of $11.7 million compared to the prior year quarter. Cost of products sold as a percentage of revenues in our fuel oil and refined fuels segment decreased from 91.1% during the third quarter of fiscal 2005 to 85.5% in the third quarter of fiscal 2006 primarily as a result of the elimination of the Ceiling Program which had the effect of restricting fuel oil margin opportunities in fiscal 2005, as well as the aforementioned improvement in product mix from the exit of certain lower margin diesel and gasoline businesses. The impact of the lost margin opportunity from the Ceiling Program in the prior year quarter was approximately $10.0 million. By eliminating this pricing program for fiscal 2006, we no longer incur the costs of hedging deliveries associated with this program and we have been successful in implementing our market-based pricing strategies in our field operations without significant customer losses.

The decrease in revenues attributable to our natural gas and electricity segment had a $1.9 million impact on cost of products sold for the three months ended June 24, 2006 compared to the prior year quarter. Cost of products sold in our HVAC segment declined $1.6 million, or 17.2%, as a result of lower revenues, partially offset by a charge of $0.8 million to reduce the carrying value of inventory that will no longer be actively marketed by our customer service centers as a result of the reorganization of our HVAC segment.

For the quarter ended June 24, 2006, total cost of products sold represented 63.2% of revenues compared to 67.2% in the prior year quarter. This decrease results primarily from the impact of the elimination of the fuel oil Ceiling Program and the efforts we have taken to eliminate lower margin business in the propane and refined fuels segments.

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Operating Expenses

(Dollars in thousands)			Three Months Ended												Decrease						Percent Decrease
			June 24, 2006						June 25, 2005
Operating expenses				$	88,183					$	99,843					$	(11,660	)			(11.7%)
As a percent of total revenues					29.0	%					30.5	%

All costs of operating our retail distribution and appliance sales and service operations are reported within operating expenses in the condensed 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 $88.2 million for the three months ended June 24, 2006 decreased $11.7 million, or 11.7%, compared to $99.8 million in the prior year quarter, primarily as a result of cost savings achieved through our field realignment which began during the fourth quarter of fiscal 2005.

As a second phase of our field realignment, during the third quarter of fiscal 2006 we initiated plans to restructure our HVAC service offerings and eliminated nearly 200 positions supporting our HVAC installation activities. These efforts, along with the first phase of our field realignment initiated in the fourth quarter of fiscal 2005, have significantly restructured our operating footprint and reduced our cost structure through the elimination of nearly 350 positions since the beginning of the fourth quarter of the prior year, as well as through the creation of routing efficiencies which has allowed us to reduce our fleet by approximately 530 vehicles. As a result, payroll and benefit related expenses declined $5.4 million and savings in other operating expenses were $3.7 million. In addition, bad debt expense decreased $2.6 million. These cost savings are significant particularly when considering the payroll and benefit related savings are net of a $0.8 million increase in variable compensation.

General and Administrative Expenses

(Dollars in thousands)			Three Months Ended												Increase						Percent Increase
			June 24, 2006						June 25, 2005
General and administrative expenses				$	13,778					$	11,804					$	1,974				16.7%
As a percent of total revenues					4.5	%					3.6	%

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 condensed consolidated statements of operations.

General and administrative expenses of $13.8 million for the three months ended June 24, 2006 increased $2.0 million, or 16.7%, compared to $11.8 million during the prior year period. The increase was primarily attributable to a $1.8 million increase in variable compensation in line with improved earnings, as well as an increase in professional services fees of $1.3 million in connection with the Proposed Exchange which was announced on July 28, 2006. We expect to incur additional professional services fees during the fourth quarter in order to consummate the Proposed Exchange.

Restructuring Costs.    For the three months ended June 24, 2006, we recorded a restructuring charge of $2.9 million related primarily to employee termination costs incurred as a result of plans initiated to streamline the operations within our HVAC business segment. These plans are expected to result in the elimination of certain low margin installation activities and reduce costs at the field operating level. The restructuring charge consists primarily of costs associated with severance and other employee benefits for an additional 200 positions eliminated during the third quarter of fiscal 2006 for a total of 350 positions eliminated since the beginning of the fourth quarter of fiscal 2005 under the field realignment plan.

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Our field realignment efforts will continue into the fourth quarter of fiscal 2006 as we focus on further streamlining the operations ahead of the fiscal 2007 heating season.

Depreciation and Amortization

(Dollars in thousands)			Three Months Ended												Decrease						Percent Decrease
			June 24, 2006						June 25, 2005
Depreciation and amortization				$	7,756					$	9,196					$	(1,440	)			(15.7%)
As a percent of total revenues					2.6	%					2.8	%

Depreciation and amortization expense decreased $1.4 million, or 15.7%, to $7.8 million for the three months ended June 24, 2006, compared to $9.2 million in the prior year quarter as a result of lower depreciation attributable to asset retirements.

Interest Expense, net

(Dollars in thousands)			Three Months Ended												Decrease						Percent Decrease
			June 24, 2006						June 25, 2005
Interest expense, net				$	9,686					$	9,943					$	(257	)			(2.6%)
As a percent of total revenues					3.2	%					3.0	%

Net interest expense decreased $0.2 million, or 2.6%, to $9.7 million for the three months ended June 24, 2006, compared to $9.9 million in the prior year quarter. The decrease results primarily from lower average amounts outstanding under our working capital facility during the third quarter of fiscal 2006.

Net Loss and EBITDA.    Net loss for the three months ended June 24, 2006 amounted to $10.5 million, an improvement of $49.4 million, or 82.5%, compared to the prior year quarter net loss of $59.9 million. Net loss for the three months ended June 25, 2005 was negatively impacted by a one-time charge of $36.2 million recorded to reflect the loss on debt extinguishment associated with the prepayment premium of the March 31, 2005 debt refinancing. EBITDA also improved to $7.1 million for the three months ended June 24, 2006 compared to an Adjusted EBITDA loss (as defined below) in the prior year quarter of $4.4 million. In addition to the impact of the prior year one-time charge, our net loss and EBITDA improved, despite lower volumes in propane and refined fuels, as a result of our effort to focus on higher margin propane and refined fuels customers, cost savings attributable to the ongoing field realignment and the impact on fuel oil margins from the elimination of 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 three and nine months ended June 25, 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.

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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:

(Dollars in thousands)			Three Months Ended
			June 24, 2006						June 25, 2005
Net loss				$	(10,473	)				$	(59,912	)
Add:
Provision for income taxes					121						138
Interest expense, net					9,686						9,943
Depreciation and amortization					7,756						9,196
EBITDA					7,090						(40,635	)
Loss on debt extinguishment					—						36,242
Adjusted EBITDA					7,090						(4,393	)
Add (subtract):
Provision for income taxes					(121	)					(138	)
Loss on debt extinguishment					—						(36,242	)
Interest expense, net					(9,686	)					(9,943	)
Gain on disposal of property, plant and equipment, net					(568	)					(821	)
Changes in working capital and other assets and liabilities					69,333						95,920
Net cash provided by/(used in)
Operating activities				$	66,048					$	44,383
Investing activities				$	(3,184	)				$	(6,182	)
Financing activities				$	(41,671	)				$	(43,895	)

Nine Months Ended June 24, 2006 Compared to Nine Months Ended June 25, 2005

Revenues

(Dollars in thousands)			Nine Months Ended												Increase (Decrease)						Percent Increase (Decrease)
			June 24, 2006						June 25, 2005
Revenues
Propane				$	895,407					$	814,275					$	81,132				10.0%
Fuel oil and refined fuels					305,412						352,708						(47,296	)			(13.4%)
Natural gas and electricity					103,716						81,931						21,785				26.6%
HVAC					70,183						82,001						(11,818	)			(14.4%)
All other					7,686						7,680						6				0.1%
Total revenues				$	1,382,404					$	1,338,595					$	43,809				3.3%

Total revenues increased $43.8 million, or 3.3%, to $1,382.4 million for the nine months ended June 24, 2006 compared to $1,338.6 million for the nine months ended June 25, 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 the National Oceanic and Atmospheric Administration (‘‘NOAA’’), average temperatures in our service territories were 10% warmer than normal for the nine months ended June 24, 2006, compared to 5% warmer than normal temperatures in the prior year period. While the fiscal 2006 heating season began with temperatures that were 5% warmer than normal in the first quarter of fiscal 2006, 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

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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 $895.4 million for the first nine months of fiscal 2006 increased $81.1 million, or 10.0%, compared to $814.3 million in the prior year period, 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 the first nine months of fiscal 2006 decreased 47.6 million gallons, or 10.8%, to 391.3 million gallons from 438.9 million gallons in the prior year period. 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 20.3% as a result of higher commodity prices for propane. The average posted price of propane during the first nine months of fiscal 2006 increased approximately 25% compared to the average posted prices in the prior year period. Additionally, included within the propane segment are revenues from wholesale and risk management activities of $52.3 million for the nine months ended June 24, 2006 which increased $26.9 million compared to the prior year period.

Revenues from the distribution of fuel oil and other refined fuels of $305.4 million in the first nine months of fiscal 2006 decreased $47.3 million, or 13.4%, from $352.7 million in the prior year. Sales of fuel oil and other refined fuels amounted to 125.1 million gallons during the first nine months of fiscal 2006 compared to 207.3 million gallons in the prior year period, a decrease of 82.2 million gallons, or 39.7%. 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 39.3 million gallons compared to the prior year period, 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 43.5% 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 the first nine months of fiscal 2006 increased approximately 28% compared to the average posted prices in the prior year period.

Revenues for the first nine months of fiscal 2006 were favorably impacted by a 26.6% increase in our natural gas and electricity marketing segment, which increased to $103.7 million from $81.9 million in the prior year period, 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 14.4%, to $70.2 million during the first nine months of fiscal 2006 compared to $82.0 million in the prior year period, primarily as a result of decreased installation activities.

Cost of Products Sold

(Dollars in thousands)			Nine Months Ended												Increase (Decrease)						Percent Increase (Decrease)
			June 24, 2006						June 25, 2005
Cost of products sold
Propane				$	521,679					$	454,808					$	66,871				14.7%
Fuel oil and refined fuels					235,973						311,134						(75,161	)			(24.2%)
Natural gas and electricity					87,124						71,621						15,503				21.6%
HVAC					27,885						32,149						(4,264	)			(13.3%)
All other					4,055						4,485						(430	)			(9.6%)
Total cost of products sold				$	876,716					$	874,197					$	2,519				0.3%
As a percent of total revenues					63.4	%					65.3	%

Cost of products sold increased $2.5 million to $876.7 million for the nine months ended June 24, 2006, compared to $874.2 million in the prior year period. The increase results primarily from

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the higher commodity prices for propane and fuel oil, offset to an extent by the lower sales volumes described above. Cost of products sold in the nine month period of fiscal 2006 include a $7.5 million unrealized (non-cash) gain representing the net change in fair values of derivative instruments during the period, compared to a $1.9 million unrealized gain in the first nine months of the prior year (see Item 3 in this Quarterly 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 $521.7 million increased $66.9 million, or 14.7%, compared to the prior year period. Higher propane prices resulted in an $89.6 million increase in cost of products sold during the first nine months of fiscal 2006 compared to the prior year period, partially offset by decreased propane volumes which had an impact of $46.2 million. Higher wholesale and risk management activities, noted above, increased cost of products sold by $22.9 million compared to the prior year period.

Cost of products sold associated with our fuel oil and refined fuels segment of $236.0 million decreased $75.2 million, or 24.2%, compared to the prior year period. Lower sales volumes resulted in a $123.4 million decrease in cost of products sold during the first nine months of fiscal 2006 compared to the prior year period, partially offset by higher commodity prices which had an impact of $48.3 million compared to the prior year period. Cost of products sold as a percentage of revenues in our fuel oil and refined fuels segment decreased from 88.2% during the first nine months of fiscal 2005 to 77.3% in the first nine months of 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 the first nine months of fiscal 2005 significantly affected margin opportunities. The lost margin opportunity from this fuel oil Ceiling Program had an estimated impact of $21.5 million on the year-over-year comparison of operating margins in the fuel oil and refined fuels segment. By eliminating this pricing program for fiscal 2006, we no longer incur the costs of hedging deliveries associated with this 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 $15.5 million impact on cost of products sold for the nine months ended June 24, 2006 compared to the prior year period. Cost of products sold in our HVAC segment declined $4.3 million as a result of lower revenues, partially offset by a charge of $0.8 million to reduce the carrying value of inventory that will no longer be actively marketed by our customer service centers.

For the nine months ended June 24, 2006, total cost of products sold represented 63.4% of revenues compared to 65.3% in the prior year period.

Operating Expenses

(Dollars in thousands)			Nine Months Ended												Decrease						Percent Decrease
			June 24, 2006						June 25, 2005
Operating expenses				$	287,971					$	305,097					$	(17,126	)			(5.6)%
As a percent of total revenues					20.8	%					22.8	%

Operating expenses of $288.0 million for the nine months ended June 24, 2006 decreased $17.1 million, or 5.6%, compared to $305.1 million in the prior year period, primarily as a result of cost savings achieved through the aforementioned field realignment efforts. As a result of these efforts, payroll and benefit related expenses decreased by $14.9 million and other operating expenses decreased $8.0 million. Partially offsetting these cost savings was a $1.6 million increase in bad debt expense due to higher energy costs and a $4.2 million increase in variable compensation costs in line with higher earnings.

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General and Administrative Expenses

(Dollars in thousands)			Nine Months Ended												Increase						Percent Increase
			June 24, 2006						June 25, 2005
General and administrative expenses				$	45,108					$	34,829					$	10,279				29.5%
As a percent of total revenues					3.3	%					2.6	%

General and administrative expenses of $45.1 million for the nine months ended June 24, 2006 were $10.3 million, or 29.5%, higher compared to $34.8 million during the first nine months of fiscal 2005. The increase was primarily attributable to $6.8 million increased variable compensation in line with improved earnings, as well as higher professional services fees in connection with assistance with certain business initiatives, including the field realignment and the recently announced Proposed Exchange. During the nine months ended June 24, 2006, we incurred professional fees of approximately $1.3 million in connection with the Proposed Exchange. We expect to incur additional professional services fees during the fourth quarter in order to consummate the Proposed Exchange.

Depreciation and Amortization

(Dollars in thousands)			Nine Months Ended												Decrease						Percent Decrease
			June 24, 2006						June 25, 2005
Depreciation and amortization				$	24,865					$	27,513					$	(2,648	)			(9.6%)
As a percent of total revenues					1.8	%					2.1	%

Depreciation and amortization expense decreased $2.6 million, or 9.6%, to $24.9 million for the nine months ended June 24, 2006, compared to $27.5 million in the prior year period as a result of lower depreciation from asset retirements. Partially offsetting this decrease was an asset impairment charge of $1.1 million in fiscal 2006 associated with our field realignment efforts, as well as the write-down of certain assets in our all other business segment.

Interest Expense, net

(Dollars in thousands)			Nine Months Ended												Increase						Percent Increase
			June 24, 2006						June 25, 2005
Interest expense, net				$	31,192					$	30,286					$	906				3.0%
As a percent of total revenues					2.3	%					2.3	%

Net interest expense increased $0.9 million, or 3.0%, to $31.2 million for the nine months ended June 24, 2006, compared to $30.3 million in the prior year period. The increase results primarily from higher average amounts outstanding under our working capital facility to fund increased working capital requirements during the fiscal 2006 heating season from higher commodity prices, offset to an extent by lower average interest rates on long-term borrowings.

Net Income and EBITDA.    Net income for the nine months ended June 24, 2006 amounted to $111.8 million, or $3.37 per Common Unit, an increase of $81.4 million, or 267.8%, compared to the prior year period of $30.4 million, or $0.97 per Common Unit. Net income for the nine months ended June 25, 2005 was negatively impacted by the one-time debt extinguishment charge of $36.2 million described above. In addition to the impact of the prior year one-time charge, net income improved $45.2 million. EBITDA increased $43.4 million, or 34.8%, to $168.2 million for the nine months ended June 24, 2006, compared to Adjusted EBITDA of $124.8 million in the prior year period. Despite weather that was 10% warmer than normal for the first nine months of fiscal 2006, and 20% warmer than normal in January and February 2006, our results were favorably impacted by the areas that are well within our control: (i) the impact of eliminating the fuel oil Ceiling Program, (ii) operating expense savings from our field realignment efforts to streamline the operating footprint and achieve operating efficiencies and, (iii) unit margin improvement from improved customer mix.

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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:

(Dollars in thousands)			Nine Months Ended
			June 24, 2006						June 25, 2005
Net income				$	111,771					$	30,446
Add:
Provision for income taxes					354						336
Interest expense, net					31,192						30,286
Depreciation and amortization					24,865						27,513
EBITDA					168,182						88,581
Loss on debt extinguishment					—						36,242
Adjusted EBITDA					168,182						124,823
Add (subtract):
Provision for income taxes					(354	)					(336	)
Loss on debt extinguishment					—						(36,242	)
Interest expense, net					(31,192	)					(30,286	)
Gain on disposal of property, plant and equipment, net					(1,189	)					(1,888	)
Gain on sale of customer service centers					—						(976	)
Changes in working capital and other assets and liabilities					(14,563	)					(32,808	)
Net cash provided by/(used in)
Operating activities				$	120,884					$	22,287
Investing activities				$	(12,425	)				$	(19,126	)
Financing activities				$	(84,994	)				$	(45,434	)

Liquidity and Capital Resources

Analysis of Cash Flows

Operating Activities.    Due to the seasonal nature of the propane and fuel oil businesses, cash flows from operating activities are greater during the winter and spring seasons (our second and third fiscal quarters) as customers pay for products purchased during the heating season. For the nine months ended June 24, 2006, net cash provided by operating activities was $120.9 million compared to net cash provided by operating activities of $22.3 million for the first nine months of the prior year. The $98.6 million improvement in operating cash flows was attributable to a $44.3 million increase in earnings, after adjusting for non-cash items in both periods (depreciation, amortization, gains on disposal of assets and loss on debt extinguishment), coupled with a $54.3 million decrease in investment in working capital in comparison to the first nine months of the prior year, particularly lower accounts receivable at the end of the fiscal 2006 heating season compared to the prior year.

In addition, during fiscal 2006 we received $4.9 million from an agreement to release to us the remaining funds previously held in escrow following the Agway Acquisition in December 2003. These funds were originally set aside by the seller to fund environmental remediation and monitoring activities related to properties acquired in the Agway Acquisition and will be used by us to fund 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.

Investing Activities.    Net cash used in investing activities of $12.4 million for the nine months ended June 24, 2006 consists of capital expenditures of $15.3 million (including $7.0 million for maintenance expenditures and $8.3 million to support the growth of operations), partially offset by the net proceeds from the sale of property, plant and equipment of $2.9 million. Net cash used in investing

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activities of $19.1 million for the nine months ended June 25, 2005 consisted of capital expenditures of $23.1 million (including $7.8 million for maintenance expenditures and $15.3 million to support growth of operations), partially offset by the net proceeds from the sale of property, plant and equipment of $4.0 million.

Financing Activities.    Net cash used in financing activities for the nine months ended June 24, 2006 of $85.0 million reflects the repayment of short-term borrowings of $27.2 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 of $57.8 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. Net cash used in financing activities for the nine months ended June 25, 2005 of $45.4 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 under our existing 6.875% senior notes due 2013 and borrowings of $125.0 million under the Term Loan. In addition, we had borrowings of $15.3 million under our Revolving Credit Agreement in order to fund increased working capital needs during the fiscal 2005 heating season, offset by $3.8 million in fees associated with the 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 of the first three quarters of fiscal 2005 amounted to $57.4 million.

Summary of Long-Term Debt Obligations and Revolving Credit Lines

Our long-term borrowings and revolving credit lines consist of $423.2 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. The 2003 Senior Notes mature on December 15, 2013 and require semi-annual interest payments that began on June 15, 2004. We are permitted to redeem some or all of the 2003 Senior Notes any time on or after December 15, 2008, at redemption prices specified in the indenture governing the 2003 Senior Notes. In addition, embedded within the 2003 Senior Notes is a change of control provision that would require us to offer to repurchase the notes at 101% of the principal amount repurchased, if the holders of the notes elected to exercise the right of repurchase.

On August 26, 2005, we executed the second amendment to the Revolving Credit Agreement pursuant to which the lenders (i) eliminated a stand-alone $75.0 million letter of credit facility and combined that facility with the existing revolving working capital facility; (ii) increased the revolving working capital facility by an additional $25.0 million, thereby raising the amount of the working capital facility from $75.0 million to $175.0 million; (iii) extended the revolving credit facility’s expiration date to match the March 31, 2010 maturity date of the Term Loan; and, (iv) amended certain other terms to effect the foregoing. 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. As of June 24, 2006 there were no amounts outstanding under the working capital facility of the Revolving Credit Agreement.

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.

The Revolving Credit Agreement and the 2003 Senior Notes both contain various restrictive and affirmative covenants applicable to our Operating Partnership and us, respectively, including (i)

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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 Operating Partnership debt to EBITDA, as adjusted for certain non-recurring charges) of less than 4.0 to 1. In addition, the Operating Partnership is required to maintain an interest coverage ratio (the ratio of EBITDA, as adjusted for certain non-recurring charges, to consolidated interest expense) of greater than 2.5 to 1 on a consolidated basis. We were in compliance with all covenants and terms of all of our debt agreements as of June 24, 2006.

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%.

Partnership Distributions

We will make distributions in an amount equal to all of our Available Cash, as defined in the Second Amended and Restated Partnership Agreement, approximately 45 days after the end of each fiscal quarter to holders of record on the applicable record dates. The Board of Supervisors reviews the level of Available Cash on a quarterly basis based upon information provided by management. On July 20, 2006, we announced a quarterly distribution of $0.6375 per Common Unit, or $2.55 on an annualized basis, in respect of the third quarter of fiscal 2006 payable on August 8, 2006 to holders of record on August 1, 2006. This quarterly distribution included the increase of $0.025 per Common Unit, or $0.10 per Common Unit on an annualized basis, previously announced on May 4, 2006. Additionally, on July 28, 2006, we announced the eleventh increase in our quarterly distribution from $0.6375 to $0.6625 per Common Unit. This increase equates to $0.10 per Common Unit on an annualized basis to $2.65 per Common Unit. The quarterly distribution at this increased level will be payable in respect of the fourth quarter of fiscal 2006 on November 14, 2006 to Common Unitholders of record on November 7, 2006.

Quarterly distributions include Incentive Distribution Rights (‘‘IDRs’’) payable to our General Partner to the extent the quarterly distribution exceeds $0.55 per Common Unit. The IDRs represent an incentive for the General Partner (which is majority-owned by the Partnership's senior management) to increase the distributions to Common Unitholders in excess of $0.55 per Common Unit. With regard to the first $0.55 of the Common Unit distribution, 98.26% of the Available Cash is distributed to the Common Unitholders and 1.74% is distributed to the General Partner. With regard to the balance of the Common Unit distributions paid, approximately 85% of the Available Cash is distributed to the Common Unitholders and approximately 15% is distributed to the General Partner. If the Proposed Exchange, as described above, is completed, the IDRs will be cancelled and the General Partner will not be entitled to receive any cash distributions in respect of its general partner interests; accordingly, all cash distributions will be paid in respect of the Common Units.

Debt Obligations and Other Commitments

The following table presents short-term and long-term debt obligations, cash interest and future minimum rental commitments due under noncancelable operating lease agreements as of June 24, 2006. For purposes of determining cash interest due under the Term Loan, a variable interest debt instrument, we have used the interest rate in effect as of June 24, 2006, taking into consideration the impact of the interest rate swap described above.

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			Payments due by period
(Dollars in thousands)			Remainder of Fiscal 2006						Fiscal 2007						Fiscal 2008						Fiscal 2009						Fiscal 2010 and thereafter						Total
Short-term and long-term debt				$	—					$	—					$	—					$	—					$	548,245					$	548,245
Future interest payments					4,256						35,603						37,731						37,731						137,870						253,191
Operating leases					6,144						17,568						13,335						8,199						10,366						55,612
Total debt obligations, cash interest and lease commitments				$	10,400					$	53,171					$	51,066					$	45,930					$	696,481					$	857,048

We have a noncontributory, cash balance format, defined benefit pension plan which was frozen to new participants effective January 1, 2000. Effective January 1, 2003, the defined benefit pension plan was amended such that future service credits ceased and eligible employees would only receive interest credits toward their ultimate retirement benefit. At June 24, 2006, we had accrued pension obligations of $44.2 million. We also provide postretirement health care and life insurance benefits for certain retired employees under a plan that was also frozen to new participants effective January 1, 2000. At June 24, 2006, we had accrued retiree health and life benefits of $32.0 million. We are self-insured for general and product, workers’ compensation and automobile liabilities up to predetermined thresholds above which third party insurance applies. At June 24, 2006, we had accrued insurance liabilities of $39.2 million, net of an $8.7 million asset related to the amount of the liability expected to be covered by insurance carriers. Additionally, we have standby letters of credit in the aggregate amount of $49.3 million, in support of our casualty insurance coverage and certain lease obligations, which expire periodically through April 15, 2007.

Additionally, 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 2013. 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 difference. Although the equipments’ fair value 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 $19.5 million. Of this amount, the fair value of residual value guarantees for operating leases entered into after December 31, 2002 were $8.3 million and $6.3 million as of June 24, 2006 and September 24, 2005, respectively, which is reflected in other liabilities, with a corresponding amount included within other assets in the accompanying condensed consolidated balance sheets.

Recently Issued Accounting Standards

In February 2006, the Financial Accounting Standards Board (the ‘‘FASB’’) issued SFAS No. 155, ‘‘Accounting for Certain Hybrid Financial Instruments – an amendment of FASB Statements No. 133 and 140’’ (‘‘SFAS 155’’). Among other things, SFAS 155 permits the fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation under SFAS 133. It also clarifies which interest-only strips and principal-only strips are not subject to the requirements of SFAS 133 and establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation. SFAS 155 is effective for all financial instruments acquired, issued, or subject to a remeasurement event occurring after our fiscal year ending September 30, 2006. We are currently evaluating the provisions of SFAS 155 and currently believe that adoption will not have a material effect on our financial position, results of operations or cash flows.

In March 2005, the FASB issued FASB Interpretation No. 47, ‘‘Accounting for Conditional Asset Retirement Obligations’’ (‘‘FIN 47’’). FIN 47 clarifies the term ‘‘conditional asset retirement obligation’’ as a legal obligation to retire an asset when the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. FIN 47 also

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requires an entity to recognize a liability for the fair value of the conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. FIN 47 is effective no later than the end of our fiscal year ending September 30, 2006. We are currently evaluating the provisions of FIN 47 and currently believe that adoption will not have a material effect on our financial position, results of operations or cash flows.

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ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

As of June 24, 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 that we sell or acquire propane or fuel oil at a fixed price at fixed future dates. An option contract allows, but does not require, its holder to buy or sell propane or fuel oil at a specified price during a specified time period. However, the writer of an option contract must fulfill the obligation of the option contract, should the holder choose to exercise the option. At expiration, the contracts are settled by the delivery of the product to the respective party or are settled by the payment of a net amount equal to the difference between the then current price and the fixed contract price. 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.

During fiscal 2005, approximately 70% of our fuel oil volumes were sold to individual customers under a Ceiling Program which was an agreement pre-establishing a maximum price per gallon over a twelve-month period. While our strategy was to enter into derivative instruments in the form of futures and options traded on the NYMEX covering a majority of the fuel oil we expected to sell to customers under the Ceiling Program in an effort to protect the margins under the program, we evaluated the costs of such hedge protection and elected not to hedge deliveries in February through April of 2005 (impacting our second and third fiscal quarters of fiscal 2005) under this program. After evaluating the costs to adequately hedge the Ceiling Program in the current fuel oil price environment, we decided to discontinue offering the Ceiling Program after the fiscal 2005 heating season. Accordingly, we have not offered the Ceiling Program for the fiscal 2006 heating season.

Market Risk

We are subject to commodity price risk to the extent that propane or fuel oil market prices deviate from fixed contract settlement amounts. Futures traded with brokers of the NYMEX require daily cash settlements in margin accounts. Forward and option contracts are generally settled at the expiration of the contract term either by physical delivery or through a net settlement mechanism. Market risks associated with 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 propane option contracts to the extent the counterparties do not perform. We evaluate the financial condition of each counterparty with which we conduct business and establish credit limits to reduce exposure to 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 new Term Loan facility under the Revolving Credit Agreement. The interest rate swap is being accounted for under SFAS 133 and has been designated as a cash flow hedge. Changes in the fair value of the interest rate swap are recognized in other comprehensive income until the hedged item is recognized in earnings. At June 24, 2006, the fair value of the interest rate swap was $4.0 million representing an unrealized gain and is included within other assets.

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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 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 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, 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 June 24, 2006, the fair value of derivative instruments described above resulted in derivative assets (unrealized gains) of $0.3 million included within prepaid expenses and other current assets and derivative liabilities (unrealized losses) of $1.3 million included within other current liabilities. Beginning with the fiscal 2006 third quarter, we report 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 year periods presented have been reclassified from operating expenses to cost of products sold for comparative purposes. Cost or products sold included unrealized (non-cash) gains in the amount of $1.0 million for the three months ended June 24, 2006, unrealized (non-cash) gains of $7.5 million for the nine months ended June 24, 2006 and unrealized (non-cash) gains in the amounts of $2.3 million and $1.9 million for the three and nine months ended June 25, 2005, respectively, attributable to the change in fair value of derivative instruments not designated as cash flow hedges. At June 24, 2006, unrealized losses on derivative instruments designated as cash flow hedges in the amount of $1.1 million were included in OCI and are expected to be recognized in earnings during the next 12 months as the hedged transactions occur. However, due to the volatility of the commodities market, the corresponding value in OCI is subject to change prior to its impact on earnings.

Sensitivity Analysis

In an effort to estimate our exposure to unfavorable market price changes in propane or fuel oil, a sensitivity analysis of open positions as of June 24, 2006 was performed. Based on this analysis, a 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 a reduction in potential future gains or potential losses in future earnings of $3.1 million as of both June 24, 2006 and June 25, 2005. See also Item 7A of our Annual Report on Form 10-K for the fiscal year ended September 24, 2005.

The above hypothetical change does not reflect the worst case scenario. Actual results may be significantly different depending on market conditions and the composition of the open position portfolio at any given point in time.

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ITEM 4.	CONTROLS AND PROCEDURES

(a)    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) that are designed to provide reasonable assurance that information required to be disclosed in the Partnership’s filings under the Securities Exchange Act of 1934 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.

The Partnership completed an evaluation under the supervision and with 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 June 24, 2006. Based on this evaluation, the Partnership’s principal executive officer and principal financial officer have concluded that as of June 24, 2006, such disclosure controls and procedures were effective at the reasonable assurance level.

(b)    There have not been any changes in the Partnership’s internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934) during the quarter ended June 24, 2006 that have materially affected or are reasonably likely to materially affect its internal control over financial reporting.

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PART II

ITEM 1A.    RISK FACTORS

Our Annual Report on Form 10-K for the fiscal year ended September 24, 2005 did not include a ‘‘Risk Factors’’ section because such disclosure was not required at the time by applicable SEC rules. The new SEC rules require inclusion of ‘‘Risk Factors’’ in a company's Annual Report on Form 10-K which would first be applicable to us for our fiscal year ending September 30, 2006. In connection with the Proposed Exchange, we have elected to include disclosure of risk factors in this Quarterly Report.

The specific risk factors set forth below should be carefully considered along with the other information contained in this Quarterly Report. Some factors in this section are ‘‘forward-looking statements.’’ See ‘‘Disclosure Regarding Forward Looking Statements’’ above.

Risks Inherent in Our Business Operations

Since weather conditions may adversely affect demand for propane, fuel oil and other refined fuels and natural gas, our results of operations and financial condition are vulnerable to warm winters.

Weather conditions have a significant impact on the demand for propane, fuel oil and other refined fuels and natural gas for both heating and agricultural purposes. Many of our customers rely heavily on propane, fuel oil or natural gas as a heating source. The volume of propane, fuel oil and natural gas sold is at its highest during the six-month peak heating season of October through March and is directly affected by the severity of the winter. Typically, we sell approximately two-thirds of our retail propane volume and approximately three-fourths of our retail fuel oil volume during the peak heating season.

Actual weather conditions can vary substantially from year to year, significantly affecting our financial performance. For example, average temperatures in our service territories were 10% warmer than normal for the nine months ended June 24, 2006 compared to 5% warmer than normal in the prior year period, as reported by NOAA. During the critical heating months of January and February 2006, average temperatures were 20% warmer than normal. Nationwide average temperatures, as reported by NOAA, averaged 7% warmer than normal in fiscal years 2005 and 2004. 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. Our ability to pay principal and interest on our indebtedness depends on the cash generated by the Operating Partnership. The Operating Partnership's financial performance is affected by weather conditions. As a result, we can make no assurances 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 distributions to our Common Unitholders, and principal and interest on our indebtedness.

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 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

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Conway, Kansas. In addition, our supply from our usual sources may be interrupted due to reasons that are beyond our control. As a result, the cost of acquiring propane, fuel oil and other refined fuels and natural gas from other suppliers might be materially higher at least on a short-term basis. Since we may not be able to pass on to our customers immediately, or in full, all increases in our wholesale cost of propane, fuel oil and other refined fuels and natural gas, these increases could reduce our profitability. We engage in transactions to hedge certain product costs from time to time in an attempt to reduce cost volatility and to help ensure availability of product during periods of short supply. We can make no assurance that future volatility in propane, refined fuel and natural gas supply costs will not have a material adverse effect on our profitability and cash flow, or our Available Cash required to pay distributions to our Common Unitholders, or principal and interest on our indebtedness.

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 multi-state propane marketers, thousands of smaller local independent marketers and farm cooperatives. Our fuel oil business competes with fuel oil distributors offering a broad range of services and prices, from full service distributors to those offering delivery only. Generally, our existing fuel oil customers, unlike our existing propane customers, own their own tanks. As a result, the competition for these customers is more intense than in our propane business, where our existing customers seeking to switch distributors may face additional transition costs and delays.

As a result of the highly competitive nature of the retail propane and fuel oil businesses, our growth within these industries depends on our ability to acquire other retail distributors, open new customer service centers, add new customers and retain existing customers. We believe our ability to compete effectively depends on reliability of service, responsiveness to customers and our ability to control expenses in order to maintain competitive prices.

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

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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 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 make 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 technology 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

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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 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.

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 cash flow and 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 above;

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

	•	issuances of debt and equity securities;

	•	our ability to control expenses;

	•	fluctuations in working capital;

	•	capital expenditures; and

	•	financial, business and other factors, a number of which will be beyond our control.

The Second Amended and Restated Agreement of Limited Partnership (the ‘‘Partnership Agreement’’) gives, and if the Proposed Exchange is completed, the restated Partnership Agreement will continue to give, 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 our Common Unitholders as well as our financial flexibility.

As of June 24, 2006, we had total outstanding borrowings of $548.2 million, including $423.2 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 bank credit facility. The payment of principal and interest on our debt will reduce the cash available to make distributions on the Common Units. In addition, we will not be able to make any distributions to our Common Unitholders if there is, or after giving effect to such distribution, there would be, an event of default under the indenture governing the 2003 Senior Notes. The amount of distributions that the Partnership makes is limited by the 2003 Senior Notes, and the amount of distributions that the Operating Partnership may make to the Partnership is limited by the Revolving Credit Agreement. 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

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make principal and interest payments depends on our future performance, which is subject to many factors, some of which are beyond our control.

Common Unitholders have limited voting rights.

A Board of Supervisors manages our operations. Holders of Common Units have only limited voting rights on matters affecting our business. Currently holders of Common Units elect three of the five members of our Board of Supervisors every three years. The other two members of the Board of Supervisors are appointed by our General Partner. If the Proposed Exchange is completed and the restated Partnership Agreement becomes effective, holders of Common Units will have a right to elect all of the members of the Board of Supervisors at the Tri-Annual Meetings of Unitholders.

Persons owning 20% or more of the Common Units cannot vote units representing more than 20% in the election or removal of Elected Supervisors.

If, at any time, any person or group beneficially owns more than 20% of the total Common Units outstanding, any Common Units owned by that person or group in excess of 20% may not be voted on the election or removal of members of the Board of Supervisors. This provision may discourage a person or group from attempting to change the Board of Supervisors, discourage a person or group from attempting to acquire us and reduce the price at which the Common Units will trade under some circumstances.

Common 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. The Common 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

	•	Common Unitholders' rights to act together to remove or replace the General Partner or take other actions under the Partnership Agreement (or if the Proposed Exchange is completed, the restated Partnership Agreement) constitute ‘‘participation in the control’’ of our business for purposes of the state's limited partnership statute.

Common Unitholders may have liability to repay distributions.

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

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

The Partnership Agreement (or if the Proposed Exchange is completed, the restated Partnership Agreement) generally allows us to issue additional limited partner interests and other equity securities

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without the approval of the Common Unitholders. Therefore, when we issue additional Common Units or securities ranking on a parity with the Common Units, each Common 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.

Tax Risks to Common 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 Common Unitholders.

The anticipated after-tax economic benefit of an investment in the 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 Common 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 Common 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 Common 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 units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our Common Unitholders and (unless and until the Proposed Exchange is completed) our General Partner because the costs will reduce our cash available for distribution.

A Common Unitholder's tax liability could exceed cash distributions on its Common Units.

Because our Common Unitholders are treated as partners to whom we allocate taxable income which could be different in amount than the cash we distribute, a Common 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 Common Unitholder will receive cash distributions equal to its allocable share of our taxable income or even the tax liability to it resulting from that income.

Ownership of Common Units may have adverse tax consequences for tax-exempt organizations and foreign investors.

Investment in Common Units by certain tax-exempt entities and foreign persons raises issues specific to them. For example, virtually all of our taxable income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be

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

There are limits on a Common 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 Common Unitholder disposes of its entire investment in us in a fully taxable transaction with an unrelated party. A Common 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 Common 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 Common 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 Common 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 Common 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 Common 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 Common 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 Common 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 Common 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 Common Unitholder's income tax return.

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

In addition to United States federal income taxes, Common Unitholders will likely be subject to other taxes, such as state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, even if the Common Unitholder does not reside in any of those jurisdictions. A Common 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 Common Unitholder to file all United States federal, state and local income tax returns that may be required of such Common Unitholder.

Common 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 Common Unitholders through the realization of taxable income by Common 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, Common 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 Common 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 Common Unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income. This would result in Common Unitholders being allocated an increased amount of taxable income.

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ITEM 6.    EXHIBITS

(a)	Exhibits

	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.

	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.

	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.

	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.

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SIGNATURES

Pursuant to the requirements 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.
August 3, 2006			By:			/s/ ROBERT M. PLANTE
Date						Robert M. Plante Vice President and Chief Financial Officer
August 3, 2006			By:			/s/ MICHAEL A. STIVALA
Date						Michael A. Stivala Controller and Chief Accounting Officer

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