Additionally, cost of products sold for the three months ended June 26, 2004 included a $0.7 million non-cash charge associated with the settlement of futures contracts that were acquired in the Acquisition. As the underlying futures and option contracts are settled the derivative assets are charged to cost of products sold as an offset to the realized gains from contract settlement. The impact on cost of products sold represents a non-cash charge resulting from the application of purchase accounting on derivative instruments acquired. In addition, the increase in revenues attributable to natural gas and electricity marketing, HVAC service activities and sales of appliances and related parts noted above had a $14.6 million impact on cost of products sold in the third quarter of fiscal 2004 compared to the prior year quarter.

For the three months ended June 26, 2004, cost of products sold represented 61.7% of revenues compared to 50.3% in the prior year quarter. The increase in the cost of products sold as a percentage of revenue during the third quarter of fiscal 2004 compared to the prior year quarter results primarily from the addition of sales from fuel oil and other refined fuels, as well as the addition of natural gas and electricity marketing. Generally, the percentage of the commodity price for fuel oil and other refined fuels on revenues tends to be between 20% and 30% higher than propane costs are as a percentage of propane revenues. Additionally, as noted above, lower margin wholesale volumes increased during the third quarter of fiscal 2004 compared to the prior year quarter. Accordingly, the different mix of product sales during the third quarter of fiscal 2004 compared to the prior year quarter has had a negative impact on this percentage comparison.

Operating Expenses.    All other costs of operating our retail distribution and appliance sales and service operations are reported within operating expenses in the consolidated statements of operations. These operating expenses include the compensation and benefits of field and direct operating support personnel, costs of operating and maintaining our vehicle fleet, overhead and other costs of our purchasing, training and safety departments and other direct and indirect costs of our customer service centers. Operating expenses increased 69.7%, or $39.6 million, to $96.4 million for the three months ended June 26, 2004 compared to $56.8 million for the three months ended June 28, 2003. Operating expenses in the third quarter of fiscal 2004 include a $0.8 million unrealized (non-cash) loss representing the net change in fair values of derivative instruments during the quarter, compared to a $0.1 million unrealized gain in the prior year quarter (see Item 3 Quantitative and Qualitative Disclosures About Market Risk for information on our policies regarding the accounting for derivative instruments).

In addition to the non-cash impact of changes in the fair value of derivative instruments, the most significant impact on operating expenses was the impact on employee, vehicle and facility costs from the addition of the Agway Energy operations. Operating expenses in the third quarter of fiscal 2004 increased primarily in the following areas: (i) $18.5 million increased employee compensation and benefit costs related to an increase in field personnel, (ii) $2.6 million increase in vehicle related costs associated with the addition of the Agway Energy fleet, (iii) $14.4 million higher costs associated with operating and maintaining our facilities from the addition of the Agway Energy customer service centers, (iv) $2.6 million increased insurance costs, and (vi) $0.5 million higher pension costs.

General and Administrative Expenses.    All costs of our back office support functions, including compensation and benefits for executives and other support functions, as well as other costs and expenses to maintain finance and accounting, treasury, legal, human resources, corporate development and the information systems functions are reported within general and administrative expenses in the consolidated statements of operations. General and administrative expenses of $12.1 million for the three months ended June 26, 2004 were $3.6 million, or 42.4%, higher than the prior year quarter of $8.5 million. The increase was primarily attributable to the impact of $1.3 million higher employee compensation and benefit costs as a result of higher profit levels and increased overall headcount to support increased activities from the Acquisition. In addition, we have incurred transition services fees in the amount of $1.4 million related to back office functions being performed by Agway, Inc. on our behalf during the first six months following the Acquisition, as well as anticipated increases in marketing, professional services and travel associated with integration activities during the third quarter of fiscal 2004 which amounted to an increase of $1.7 million. These increases were offset by favorable spending in other expense categories in the amount of $0.8 million.

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Restructuring Costs.    During the third quarter of fiscal 2004, in connection with the initial integration of certain management and back office functions of Agway Energy, we recorded a $0.2 million restructuring charge associated with employee termination and other benefit costs incurred as a result of actions taken during the quarter. The restructuring and integration of our field and back office functions will continue throughout the remainder of fiscal 2004 in order to achieve the anticipated synergies from the combined operations. As a result, additional restructuring charges including severance, costs of vacating duplicative facilities and contract termination and other exit costs, as well as asset impairment charges are expected to be incurred during the fourth quarter of fiscal 2004.

Impairment of Goodwill.    During the third quarter of fiscal 2004, as a result of continued losses in one of our reporting units acquired in fiscal 1999, we recorded a non-cash charge of $3.2 million related to goodwill impairment.

Depreciation and Amortization.    Depreciation and amortization expense increased $2.5 million, or 37.3%, to $9.2 million for the three months ended June 26, 2004 primarily as a result of the additional depreciation and amortization attributable to the acquired property, plant and equipment and identifiable intangible assets.

(Loss) Before Interest Expense and Income Taxes and EBITDA.    (Loss) before interest expense and income taxes of $14.1 million in the three months ended June 26, 2004 increased $11.6 million compared to a loss of $2.5 million in the prior year quarter. The $11.6 million increased loss before interest expense and income taxes was unfavorably impacted by (i) the $3.2 million non-cash charge for the impairment of goodwill; (ii) $2.5 million increased depreciation and amortization expenses described above; (iii) the $0.2 million restructuring charge recorded in the third quarter of fiscal 2004; (iv) the $0.7 million non-cash charge included within cost of products sold associated with the settlement of futures contracts that were acquired in the Acquisition; and (v) the net result of higher margins from the nearly 100% increase in revenues, offset by an increase of approximately 66% in combined operating and general and administrative expenses to support increased level of field operations.

Earnings before interest, taxes, depreciation and amortization ("EBITDA") amounted to a loss of $4.9 million for the three months ended June 26, 2004, compared to earnings of $3.2 million for the prior year quarter. EBITDA represents net (loss) income before deducting interest expense, income taxes, depreciation and amortization. Our management uses EBITDA as a measure of liquidity and we are including it because we believe that it provides our investors and industry analysts with additional information to evaluate our ability to meet our debt service obligations and to pay our quarterly distributions to holders of our Common Units. Moreover, our senior note agreements and our Revolving Credit Agreement require us to use EBITDA as a component in calculating our leverage and interest coverage ratios. EBITDA is not a recognized term under generally accepted accounting principles ("GAAP") and should not be considered as an alternative to net income or net cash provided by operating activities determined in accordance with GAAP. Because EBITDA as determined by us excludes some, but not all, items that affect net income, it may not be comparable to EBITDA or similarly titled measures used by other companies. The following table sets forth (i) our calculation of EBITDA and (ii) a reconciliation of EBITDA, as so calculated, to our net cash provided by operating activities (amounts in thousands):

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				Three Months Ended
				June 26, 2004				June 28, 2003
Net loss				$	(24,337	)		$	(11,935	)
Add:
Benefit for income taxes					(283	)			(64	)
Interest expense, net					10,547				8,480
Depreciation and amortization					9,177				6,717
EBITDA					(4,896	)			3,198
Add / (subtract):
Benefit for income taxes					283				64
Interest expense, net					(10,547	)			(8,480	)
Loss (gain) on disposal of property, plant and equipment, net					8				(166	)
Gain on sale of customer service centers					(619	)			(79	)
Changes in working capital and other assets and liabilities					93,673				51,020
Net cash provided by operating activities				$	77,902			$	45,557
Net cash used in investing activities				$	(4,464	)		$	(1,205	)
Net cash (used in) provided by financing activities				$	(19,093	)		$	10,655

Interest Expense.    Net interest expense increased $2.0 million, or 23.5%, to $10.5 million in the third quarter of fiscal 2004 compared to $8.5 million in the prior year quarter. The increase in net interest expense is a result of the net impact of the addition of $175.0 million of 6.875% senior notes associated with financing for the Acquisition of Agway Energy, offset by $42.5 million lower amounts outstanding under our 7.54% senior notes as a result of the repayment of a portion of the principal on July 1, 2003.

Discontinued Operations.    As part of our overall business strategy, we continually monitor and evaluate our existing operations to identify opportunities that will allow us to optimize our return on assets employed by selectively consolidating or divesting operations in slower growing or non-strategic markets. In line with that strategy, we sold a customer service center in Virginia during the third quarter of fiscal 2004 for total cash proceeds of approximately $0.8 million. We recorded a gain on sale of approximately $0.6 million, which has been accounted for within discontinued operations pursuant to Statement of Financial Accounting Standards ("SFAS") No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS 144"). Additionally, discontinued operations for the three months ended June 26, 2003 and June 28, 2003 includes $0.6 million and $1.1 million, respectively, related to losses generated from the customer service centers discontinued in the current and prior year.

Nine Months Ended June 26, 2004 Compared to Nine Months Ended June 28, 2003

Revenues.    Revenues increased $447.4 million, or 72.7%, to $1,062.6 million for the nine months ended June 26, 2004 compared to $615.2 million for the nine months ended June 28, 2003. Revenues from retail propane activities of $650.7 million for the nine months ended June 26, 2004 increased $113.9 million, or 21.2%, compared to $536.8 million in the prior year period. This increase is the result of an increase in propane sales volumes, coupled with an increase in average selling prices in line with higher commodity prices for propane. Despite nationwide average temperatures, as reported by NOAA, that were 7% warmer than normal and 9% warmer than the prior year, retail propane gallons sold increased 38.9 million gallons, or 9.4%, to 451.4 million gallons for the nine months ended June 26, 2004. The increase is primarily attributable to the addition of Agway Energy from the date of the Acquisition, offset to an extent by the impact of the warmer temperatures. Average selling prices increased approximately 8.0% as a result of sustained higher commodity prices for propane. The average posted price of propane during the first nine months of fiscal 2004 increased approximately 12% compared to the average posted prices in the prior year period.

Revenues from sales of fuel oil and other refined fuels amounted to $219.6 million for the nine months ended June 26, 2004 attributable to 163.9 million gallons sold from the addition of Agway

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Energy on December 23, 2003. Revenues from wholesale and risk management activities of $35.4 million for the nine months ended June 26, 2004 increased $22.2 million, compared to revenues of $13.2 million for the nine months ended June 28, 2003. Revenue from other sources, including natural gas and electricity marketing to deregulated markets, HVAC service activities and sales of appliances and related parts, of $156.9 million for the nine months ended June 26, 2004 increased $91.7 million compared to other revenue in the prior year period of $65.2 million. The increase in other revenues is primarily attributable to the addition of sales of natural gas and electricity and service and maintenance revenues from Agway Energy.

Cost of Products Sold.    Cost of products sold increased $323.8 million to $622.6 million for the nine months ended June 26, 2004 compared to $298.8 million in the prior year period. The increase results primarily from the increase in retail propane volumes sold, as well as the addition of fuel oil and other refined fuel sales volumes, which had a combined impact of $192.5 million on the year-over-year comparison of cost of products sold. Higher commodity prices for propane during the first nine months of fiscal 2004 also resulted in an increase in cost of products sold by $41.1 million compared to the prior year. Increased wholesale and risk management activities, noted above, caused an increase of $23.2 million in cost of products sold compared to the prior year period.

Additionally, cost of products sold for the nine months ended June 26, 2004 included a $6.3 million non-cash charge associated with the settlement of futures contracts that were acquired in the Acquisition. As the underlying futures and option contracts are settled the derivative assets are charged to cost of products sold as an offset to the realized gains from contract settlement. The impact on cost of products sold represents a non-cash charge resulting from the application of purchase accounting on derivative instruments acquired. In addition, the increase in revenues attributable to natural gas and electricity marketing, HVAC service activities and sales of appliances and related parts noted above had a $60.7 million impact on cost of products sold in the nine months ended June 26, 2004 compared to the prior year period. For the nine months ended June 26, 2004, cost of products sold represented 58.6% of revenues compared to 48.6% in the prior year period. As described in the three month comparison above, the increase in the cost of products sold as a percentage of revenue during the first nine months of fiscal 2004 compared to the prior year period results primarily from the different mix of products sold during fiscal 2004 as a result of the additional product offerings from the Agway Energy operations.

Operating Expenses.    Operating expenses of $264.3 million for the nine months ended June 26, 2004 increased $88.1 million, or 50.0%, compared to $176.2 million for the prior year period. Operating expenses for the nine months ended June 26, 2004 include a $0.5 million unrealized (non-cash) loss representing the net change in fair values of derivative instruments during the period, compared to a $1.2 million unrealized loss in the prior year period (see Item 3 Quantitative and Qualitative Disclosures About Market Risk for information on our policies regarding the accounting for derivative instruments). In addition to the non-cash impact of changes in the fair value of derivative instruments, operating expenses increased $88.8 million as a result of (i) $43.4 million increased employee compensation and benefit costs associated with the addition of Agway Energy personnel and increased earnings, (ii) $10.2 million increased costs for operating our fleet as a result of the addition of the Agway Energy fleet, (iii) $17.1 million higher costs to operate the additional customer service centers acquired, (iv) $5.3 million incremental insurance costs, (v) $1.6 million higher pension costs, and (vi) $1.5 million higher medical costs.

General and Administrative Expenses.    General and administrative expenses of $40.0 million for the nine months ended June 26, 2004 were $12.3 million, or 44.4%, higher than the prior year period of $27.7 million. The increase was primarily attributable to the impact of $6.3 million higher employee compensation and benefit costs as a result of higher profit levels and increased overall headcount, as well as $4.2 million related to transition services fees paid to Agway, Inc. for back office support provided subsequent to the Acquisition. In addition, we incurred anticipated increases in marketing, professional services and travel expenses during the first nine months of fiscal 2004 associated with our efforts to acquire Agway Energy during the first quarter and in connection with our integration efforts during the second and third quarters of fiscal 2004.

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Restructuring Costs.    As discussed in more detail in the three month comparison above, during the nine months ended June 26, 2004, we recorded a $2.4 million restructuring charge associated with employee termination and other benefit costs incurred as a result of actions taken during the second and third quarters of fiscal 2004 to integrate certain management and back office functions of Agway Energy.

Impairment of Goodwill.    During the third quarter of fiscal 2004, as a result of continued losses in one of our reporting units acquired in fiscal 1999, we recorded a non-cash charge of $3.2 million related to goodwill impairment.

Depreciation and Amortization.    Depreciation and amortization expense increased 24.9% to $25.6 million for the nine months ended June 26, 2004 compared to $20.5 million for the prior year period, primarily as a result of the additional depreciation and amortization associated with the acquired tangible and intangible assets from the Agway Energy Acquisition.

Income Before Interest Expense and Income Taxes and EBITDA.     ncome before interest expense and income taxes of $104.4 million in the nine months ended June 26, 2004 increased $12.4 million, or 13.5%, compared to $92.0 million in the prior year period. EBITDA amounted to $144.9 million for the nine months ended June 26, 2004, compared to $116.4 million for the prior year period, an increase of $28.5 million, or 24.5%. The increases in income before interest expense and income taxes and in EBITDA compared to the prior year period reflects the favorable impact on revenues and related margins from the addition of the Agway Energy operations. This favorable impact was offset, to an extent, by the added operating and general and administrative costs to support the increased level of field operations, as well as to support integration and restructuring activities. Additionally, the warmer than normal temperatures experienced during the nine months ended June 26, 2004, described above, negatively impacted volumes for the period compared to the prior year. In addition, the $14.8 million gain reported during the nine months ended June 26, 2004 and the $2.5 million gain reported during the nine months ended June 28, 2003 from the sale of customer service centers (reported within discontinued operations) had a favorable impact on EBITDA in both the current and prior year periods.

EBITDA represents net income before deducting interest expense, income taxes, depreciation and amortization. Our management uses EBITDA as a measure of liquidity and we are including it because we believe that it provides our investors and industry analysts with additional information to evaluate our ability to meet our debt service obligations and to pay our quarterly distributions to holders of our Common Units. Moreover, our senior note agreements and our Revolving Credit Agreement require us to use EBITDA as a component in calculating our leverage and interest coverage ratios. EBITDA is not a recognized term under generally accepted accounting principles ("GAAP") and should not be considered as an alternative to net income or net cash provided by operating activities determined in accordance with GAAP. Because EBITDA as determined by us excludes some, but not all, items that affect net income, it may not be comparable to EBITDA or similarly titled measures used by other companies. The following table sets forth (i) our calculation of EBITDA and (ii) a reconciliation of EBITDA, as so calculated, to our net cash provided by operating activities (amounts in thousands):

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				Nine Months Ended
				June 26, 2004				June 28, 2003
Net income				$	88,314			$	69,625
Add:
(Benefit) provision for income taxes					(117	)			103
Interest expense, net					31,028				26,212
Depreciation and amortization					25,629				20,490
EBITDA					144,854				116,430
Add / (subtract):
Benefit (provision) for income taxes					117				(103	)
Interest expense, net					(31,028	)			(26,212	)
Gain on disposal of property, plant and equipment, net					(153	)			(486	)
Gain on sale of customer service centers					(14,824	)			(2,483	)
Changes in working capital and other assets and liabilities					2,270				(18,223	)
Net cash provided by operating activities				$	101,236			$	68,923
Net cash used in investing activities				$	(204,104	)		$	(531	)
Net cash provided by (used in) financing activities				$	202,874			$	(18,469	)

Interest Expense.    Net interest expense increased $4.8 million, or 18.3%, to $31.0 million in the first nine months of fiscal 2004 compared to $26.2 million in the prior year period, primarily as a result of the net impact of the addition of $175.0 million of 6.875% senior notes associated with financing for the Acquisition, offset by $42.5 million lower amounts outstanding under our 7.54% senior notes. In addition, we incurred a one-time fee of $1.9 million related to financing commitments for the Acquisition during the first quarter of fiscal 2004.

Discontinued Operations.    During the first nine months of fiscal 2004, we sold eleven customer service centers in Texas, Oklahoma, Missouri, Kansas and Virginia for total cash proceeds of approximately $24.8 million. We recorded a gain on sale of approximately $14.8 million, which has been accounted for within discontinued operations. In the prior year, we sold nine customer service centers for total cash proceeds of approximately $7.2 million, resulting in a gain on sale of approximately $2.5 million. Additionally, on July 2, 2004 (subsequent to the end of the third quarter of fiscal 2004) we sold three customer service centers in North Carolina for total cash proceeds of $1.1 million and will record a gain on sale during the fourth quarter of fiscal 2004 of approximately $0.4 million. In accordance with SFAS 144, the individual captions on the consolidated statements of operations for the nine months ended June 26, 2004 and June 28, 2003 exclude the results from these discontinued operations, as well as certain other operations that were considered held for sale as of June 26, 2004. The net impact on our discontinued operations was not significant for the nine months ended June 26, 2004 and resulted in income from discontinued customer service centers of $1.4 million for the nine months ended June 28, 2003.

Liquidity and Capital Resources

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 26, 2004, net cash provided by operating activities was $101.2 million compared to net cash provided by operating activities of $68.9 million for the nine months ended June 28, 2003. The $32.3 million, or 46.9%, increase was attributable to the $28.5 million, or 24.5%, increase in EBITDA for the nine months ended June 26, 2004 compared to the prior year period resulting primarily from the contribution from the Agway Energy operations since December 23, 2003, offset slightly by an increase in interest expense of $4.8 million and a net impact of $8.6 million from non-cash items (gains on sales of discontinued customer service centers and the goodwill impairment charge) impacting EBITDA in both periods. Additionally, the investment working capital for the nine months ended

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June 26, 2004 decreased approximately $17.2 million compared to the comparable period in the prior year. The lower investment in working capital results primarily from an improvement in collections on accounts receivable and an increase in accrued employment and benefits due to timing of accrual payouts.

Net cash used in investing activities of $204.1 million for the nine months ended June 26, 2004 consists of the net impact of the total cost of the Acquisition of Agway Energy of approximately $211.2 million, offset to an extent by net proceeds from the sale of customer service centers during fiscal 2004 of $24.8 million and net proceeds of $0.8 million from the sale of property, plant and equipment. Additionally, capital expenditures amounted to $18.5 million (including $4.4 million for maintenance expenditures and $14.1 million to support the growth of operations) for the nine months ended June 26, 2004. Net cash used in investing activities of $0.5 million during the nine months ended June 28, 2003 consisted of net proceeds from the sale of customer service centers of $7.2 million and net proceeds of $1.7 million from the sale of property, plant and equipment, offset by capital expenditures of $9.4 million (including $2.8 million for maintenance expenditures and $6.6 million to support the growth of operations).

Net cash provided by financing activities for the nine months ended June 26, 2004 was $202.9 million as a result of (i) the issuance of $175.0 million aggregate principal amount of 6.875% senior notes due 2013, a portion of which was used to fund a portion of the Acquisition and, (ii) the net proceeds of $87.6 million from a public offering of 2,990,000 Common Units (including full exercise of the underwriters' over-allotment option) during December 2003 to fund a portion of the Acquisition; offset by (i) the payment of our quarterly distributions of $0.5875 per Common Unit during each of the first two quarters of fiscal 2004 and $0.60 per Common Unit during the third quarter of fiscal 2004 amounting to $53.4 million for the first nine months of fiscal 2004 and, (ii) $5.9 million in fees associated with the issuance of the senior notes noted above. Net cash used in financing activities for the nine months ended June 28, 2003 was $18.5 million as a result of (i) the payments of our quarterly distributions of $0.5750 per Common Unit during the first, second and third quarters of fiscal 2003 amounting to $43.6 million, (ii) the repayment of all outstanding borrowings under our Revolving Credit Agreement amounting to $46.0 million, (iii) the payment of $0.8 million in fees associated with the renewal and extension of our Revolving Credit Agreement during May 2003; offset by net proceeds of $72.4 million from the public offering of approximately 2.6 million Common Units (including full exercise of the underwriters' over-allotment option) which was completed during the third quarter of fiscal 2003.

On December 23, 2003, we issued $175.0 million aggregate principal amount of senior notes with an annual interest rate of 6.875% pursuant to Rule 144A and Regulation S of the Securities Act of 1933. On May 13, 2004, pursuant to a registration rights agreement, we exchanged these unregistered senior notes with $175.0 million aggregate principal amount of registered senior notes which have substantially the same terms (the "2003 Senior Notes"). We used approximately $122.4 million from the issuance of the 6.875% senior notes to fund a portion of the total cost of the Acquisition and the remaining net proceeds for general partnership purposes, which include working capital purposes, capital expenditures or debt reduction. Our obligations under the 2003 Senior Notes are unsecured and will 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, the senior notes and other liabilities of the Operating Partnership. The 2003 Senior Notes will mature December 15, 2013, and require semiannual interest payments that began on June 15, 2004. We may 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 (the "2003 Senior Note Agreement"). The 2003 Senior Note Agreement contains certain restrictions applicable to us and certain of our subsidiaries with respect to (i) the incurrence of additional indebtedness; and (ii) liens, investments, guarantees, loans, advances, payments, mergers, consolidations, distributions, sales of assets and other transactions.

On March 5, 1996, pursuant to a Senior Note Agreement (the "1996 Senior Note Agreement"), our Operating Partnership issued $425.0 million of senior notes (the "1996 Senior Notes") with an annual interest rate of 7.54%. Our Operating Partnership's obligations under the 1996 Senior Note

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Agreement are unsecured and rank on an equal and ratable basis with its obligations under the 2002 Senior Note Agreement and the Revolving Credit Agreement discussed below. Under the terms of the 1996 Senior Note Agreement, our Operating Partnership became obligated to pay the principal on the 1996 Senior Notes in equal annual payments of $42.5 million starting July 1, 2002, with the last such payment due June 30, 2011. On July 1, 2002, we received net proceeds of $42.5 million from the issuance by our Operating Partnership of 7.37% Senior Notes due June, 2012 (the "2002 Senior Notes") and used the funds to pay the first annual principal payment of $42.5 million due under the 1996 Senior Note Agreement. Our Operating Partnership's obligations under the agreement governing the 2002 Senior Notes (the "2002 Senior Note Agreement") are unsecured and rank on an equal and ratable basis with its obligations under the 1996 Senior Note Agreement and the Revolving Credit Agreement. Rather than refinance the second annual principal payment of $42.5 million due under the 1996 Senior Note Agreement, we elected to repay this principal payment on June 30, 2003 (the fourth quarter of fiscal 2003). On July 1, 2004 (subsequent to the end of the third quarter of fiscal 2004) we also elected to repay the third annual principal payment of $42.5 million due under the 1996 Senior Note Agreement.

Our Operating Partnership's Revolving Credit Agreement, which provided a $75.0 million working capital facility and a $25.0 million acquisition facility, matures on May 31, 2006. Borrowings under the Revolving Credit Agreement bear interest at a rate based upon either LIBOR plus a margin, Wachovia National Bank's prime rate or the Federal Funds rate plus ½ of 1%. An annual fee ranging from .375% to .50%, based upon certain financial tests, is payable quarterly whether or not borrowings occur. As of June 26, 2004 and September 27, 2003, there were no borrowings outstanding under the Revolving Credit Agreement. As of June 26, 2004, we had $60.0 million of unused borrowing capacity under the working capital facility of our Revolving Credit Agreement, after considering the impact on borrowing availability from outstanding letters of credit associated with our casualty insurance coverage and certain operating lease obligations. We are currently evaluating the adequacy of the borrowing capacity provided under the Revolving Credit Agreement in light of the additional seasonal cash needs of Agway Energy, as well as any future needs that may arise as a result of our growth initiatives. Although not currently contemplated, we may need to increase the borrowing capacity of the Revolving Credit Agreement in the future to accommodate seasonal working capital requirements associated with the added business activity from Agway Energy.

The 1996 Senior Note Agreement, the 2002 Senior Note Agreement and the Revolving Credit Agreement contain various restrictive and affirmative covenants applicable to the Operating Partnership, including (a) maintenance of certain financial tests, including, but not limited to, a leverage ratio of less than 5.0 to 1, an interest coverage ratio in excess of 2.5 to 1 and a leverage ratio of less than 5.25 to 1 when the underfunded portion of our pension obligations is used in the computation of the ratio, (b) restrictions on the incurrence of additional indebtedness, and (c) restrictions on certain liens, investments, guarantees, loans, advances, payments, mergers, consolidations, distributions, sales of assets and other transactions. During July 2004, we became aware that, as a result of our assumption from Agway Energy of arrangements for the servicing of certain receivables in the normal course of business, defaults had occurred under certain restrictive covenants of the 1996 Senior Note Agreement, the 2002 Senior Note Agreement and the Revolving Credit Agreement. On July 19, 2004, we received, in respect of each of these agreements, waivers of all past defaults and consents to continue the receivable arrangements in the normal course of business.

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 22, 2004, we declared an increase in our quarterly distribution to $0.6125 per Common Unit, or $2.45 on an annualized basis, in respect of the third quarter of fiscal 2004 payable on August 10, 2004 to holders of record on August 3, 2004, compared to $0.60 per Common Unit in respect of the second quarter of fiscal 2004, $0.5875 per Common Unit in the first quarter of fiscal 2004 and for the third

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quarter of the prior year. This increase represents our second quarterly distribution increase of fiscal 2004 and our ninth overall since our inception.

Quarterly distributions include Incentive Distribution Rights ("IDRs") payable to the General Partner to the extent the quarterly distribution exceeds $0.55 per Common Unit. The IDRs represent an incentive for the General Partner (which is owned by the management of the Partnership) 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, 98.46% of the Available Cash is distributed to the Common Unitholders and 1.54% is distributed to the General Partner (98.29% and 1.71%, respectively, prior to our December 2003 public offering). With regard to the balance of the Common Unit distributions paid, 85% of the Available Cash is distributed to the Common Unitholders and 15% is distributed to the General Partner.

Long-Term Debt Obligations and Other Commitments

Long-term debt obligations and future minimum rental commitments under noncancelable operating lease agreements as of June 26, 2004 are due as follows (amounts in thousands):

				Remainder of Fiscal 2004				Fiscal 2005				Fiscal 2006				Fiscal 2007				Fiscal 2008 and thereafter				Total
Long-term debt				$	42,500			$	42,940			$	42,975			$	42,500			$	387,500			$	558,415
Operating leases					6,129				18,475				12,086				7,640				7,232				51,562
Total long-term debt obligations and lease commitments				$	48,629			$	61,415			$	55,061			$	50,140			$	394,732			$	609,977

Additionally, we have standby letters of credit in the aggregate amount of $48.4 million, in support of our casualty insurance coverage and certain lease obligations, which expire periodically through April 15, 2005.

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 2010. 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 equipment's 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 $16.1 million. Of this amount, the fair value of residual value guarantees for operating leases entered into after December 31, 2002 was $2.8 million and $2.1 million which is reflected in other liabilities, with a corresponding amount included within other assets, in the accompanying condensed consolidated balance sheets as of both June 26, 2004 and September 27, 2003, respectively.

Public Offering

On December 16, 2003, we sold 2,600,000 Common Units in a public offering at a price of $30.90 per Common Unit realizing proceeds of $76.0 million, net of underwriting commissions and other offering expenses. On December 23, 2003, following the underwriters' full exercise of their over-allotment option, we sold an additional 390,000 Common Units at $30.90 per Common Unit, generating additional net proceeds of $11.6 million. The aggregate net proceeds of $87.6 million were used to fund a portion of the purchase price for the Acquisition. These transactions increased the total number of Common Units outstanding to 30,256,767. As a result of the Public Offering, the combined General Partner interest was reduced from 1.71% to 1.54% while the Common Unitholder interest increased from 98.29% to 98.46%.

Recently Issued Accounting Standards

On March 31, 2004, the Emerging Issues Task Force ("EITF") reached a consensus under EITF 03-6 "Participating Securities and the Two-Class Method Under FAS 128" ("EITF 03-6") which

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requires, among other things, the use of the two-class method of computing earnings per unit when participating securities exist. The two-class method is an earnings allocation formula that computes earnings per unit for each class of common stock and participating security according to dividends declared and participation rights in undistributed earnings. We are currently in the process of evaluating the applicability of the EITF 03-6 consensus on our structure, particularly in relation to the general partner's interest in net income and distributions declared, as well as the IDRs described in the Liquidity and Capital Resources section above. The consensus is effective for fiscal periods beginning after March 31, 2004 and, if deemed applicable to us, will be effective for the fiscal year ended September 25, 2004 and will require restatement of prior period earnings per unit to conform to the computation in the consensus guidance.

If EITF 03-6 is deemed applicable to us and if we were to have adopted the consensus at the end of the third quarter of fiscal 2004, the following would have been the impact on basic net income per Common Unit for the nine months ended June 26, 2004 and June 28, 2003:

				Nine Months Ended
				June 26, 2004				June 28 2003
As reported				$	2.93			$	2.74
As computed under EITF 03-6				$	2.79			$	2.62

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Disclosure Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q contains Forward-Looking Statements as defined in the Private Securities Litigation Reform Act of 1995 relating to the Partnership's future business expectations and predictions and financial condition and results of operations. Some of these statements can be identified by the use of forward-looking terminology such as "prospects," "outlook," "believes," "estimates," "intends," "may," "will," "should," "anticipates," "expects" or "plans" or the negative or other variation of these or similar words, or by discussion of trends and conditions, strategies or risks and uncertainties. These Forward-Looking Statements involve certain risks and uncertainties that could cause actual results to differ materially from those discussed or implied in such Forward-Looking Statements. The risks and uncertainties and their impact on the Partnership's operations include, but are not limited to, the following risks:

•	The impact of weather conditions on the demand for propane, fuel oil and other refined fuels;

•	Fluctuations in the unit cost of propane, fuel oil and other refined fuels;

•	The ability of the Partnership to compete with other suppliers of propane, fuel oil and other energy sources;

•	The impact on propane, fuel oil and other refined fuel prices and supply from the political, military and economic instability of the oil producing nations, global terrorism and other general economic conditions;

•	The ability of the Partnership to realize fully, or within the expected time frame, the expected cost savings and synergies from the acquisition of Agway Energy;

•	The ability of the Partnership to acquire and maintain reliable transportation for its propane, fuel oil and other refined fuels;

•	The ability of the Partnership to retain customers;

•	The impact of energy efficiency and technology advances on the demand for propane and fuel oil;

•	The ability of management to continue to control expenses;

•	The impact of changes in applicable statutes and government regulations, or their interpretations, including those relating to the environment and global warming and other regulatory developments on the Partnership's business;

•	The impact of legal proceedings on the Partnership's business;

•	The Partnership's ability to implement its expansion strategy into new business lines and sectors; and

•	The Partnership's ability to integrate acquired businesses successfully.

On different occasions, the Partnership or its representatives have made or may make Forward-Looking Statements in other filings that the Partnership makes with the SEC, in press releases or in oral statements made by or with the approval of one of its authorized executive officers. Readers are cautioned not to place undue reliance on Forward-Looking or Cautionary Statements, which reflect management's opinions only as of the date made. The Partnership undertakes no obligation to update any Forward-Looking or Cautionary Statement. All subsequent written and oral Forward-Looking Statements attributable to the Partnership or persons acting on its behalf are expressly qualified in their entirety by the Cautionary Statements in this Quarterly Report and in future SEC reports.

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ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

As of June 26, 2004, 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 its 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; the writer of an option contract must fulfill the obligation of the option contract, should the holder choose to exercise the option. At expiration, the contracts are settled by the delivery of the product to the respective party or are settled by the payment of a net amount equal to the difference between the then current price and the fixed contract price. The contracts are entered into in anticipation of market movements and to manage and hedge exposure to fluctuating prices of propane and fuel oil, as well as to help ensure the availability of product during periods of high demand.

Market risks associated with the trading of futures, options and forward contracts are monitored daily for compliance with our Commodity 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.

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.

Credit Risk

Futures are guaranteed by the NYMEX and, as a result, have minimal credit risk. We are subject to credit risk with forward and option contracts to the extent the counterparties do not perform. We evaluate the financial condition of each counterparty with which we conduct business and establish credit limits to reduce exposure to credit risk of non-performance.

Derivative Instruments

We account for derivative instruments in accordance with the provisions of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133"), as amended by SFAS No. 137 and SFAS No. 138. All derivative instruments are reported on the balance sheet, within other current assets or other current liabilities, at their fair values. Fair values for forward contracts and futures are derived from quoted market prices for similar instruments traded on the NYMEX. On the date that futures, forward and option contracts are entered into, we make a determination as to whether the derivative instrument qualifies for designation as a hedge. 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 it is, the type of hedge. For derivative instruments designated as cash flow hedges, we formally assess, both at the hedge contract's inception and on an ongoing basis, whether the hedge contract is highly effective in offsetting changes in cash flows of hedged items. Changes in the fair value of derivative instruments designated as cash flow hedges are reported in OCI to the extent effective and reclassified into cost of products sold during the same period in which the hedged item affects earnings. The mark-to-market gains or losses on ineffective portions of cash flow hedges 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 operating expenses. A portion of our option contracts are not

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

At June 26, 2004, the fair value of derivative instruments described above resulted in derivative assets of $6.7 million included within prepaid expenses and other current assets and derivative liabilities of $0.2 million included within other current liabilities. Operating expenses include unrealized (non-cash) losses in the amount of $0.8 million for the three months ended June 26, 2004 and unrealized gains in the amount of $0.1 million for the three months ended June 28, 2003 attributable to the change in fair value of derivative instruments not designated as hedges. Operating expenses include unrealized losses in the amount of $0.5 million for the nine months ended June 26, 2004 and unrealized losses in the amount of $1.2 million for the nine months ended June 28, 2003 attributable to the change in fair value of derivative instruments not designated as hedges. At June 26, 2004, unrealized gains on derivative instruments designated as cash flow hedges in the amount of $1.6 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 the exposure of unfavorable market price movements, a sensitivity analysis of open positions as of June 26, 2004 was performed. Based on this analysis, a hypothetical 10% adverse change in market prices for each of the future months for which an option, futures and/or forward contract exists indicates either a reduction in potential future gains or potential losses in future earnings of $2.9 million and $2.5 million as of June 26, 2004 and June 28, 2003, respectively. See also Item 7A of our Annual Report on Form 10-K for the fiscal year ended September 27, 2003.

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

Our management, including our principal executive officer and principal financial officer, have evaluated the effectiveness of our "disclosure controls and procedures" (as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934) as of June 26, 2004. Based on such evaluation, our principal executive officer and principal financial officer have concluded that as of June 26, 2004, such disclosure controls and procedures are effective for the purpose of ensuring that material information required to be in this Quarterly Report on Form 10-Q is made known to them by others on a timely basis. Other than the impact of the recently completed acquisition of Agway Energy, there have not been any changes in our internal control over financial reporting (as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934) during the quarter ending June 26, 2004 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting. As a result of the Acquisition, and the process of incorporating and changing the systems and processes utilized by Agway Energy, we have had to modify our internal control structure over financial reporting. We believe we are taking the necessary steps to monitor and maintain appropriate internal controls over financial reporting during this period of transition.

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PART II

ITEM 1.    LEGAL PROCEEDINGS

On May 23, 2001, our Operating Partnership was named as an additional defendant in an action previously brought by Heritage Propane Partners against SCANA Corporation and Cornerstone Ventures, L.P. arising out of our acquisition of substantially all of the propane assets of SCANA in November of 1999. We believe that all of the claims asserted against our Operating Partnership are without merit and are defending the action vigorously. The court has entered an order setting this matter for trial beginning on October 4, 2004. At the close of discovery, we intend to file a motion for summary judgment to dismiss the claims asserted against our Operating Partnership. See additional discussion of this matter in the Annual Report on Form 10-K for the most recent fiscal year ended September 27, 2003.

ITEM 6.     EXHIBITS AND REPORTS ON FORM 8-K

(a)    Exhibits

31.1	Certification of the President and Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

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 President and Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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.

(b)    Reports on Form 8-K

No reports were filed on Form 8-K.

Other items under Part II are not applicable.

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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 10, 2004				/s/ ROBERT M. PLANTE
Date				Robert M. Plante Vice President and Chief Financial Officer
August 10, 2004				/s/ MICHAEL A. STIVALA
Date				Michael A. Stivala Controller (Principal Accounting Officer)

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