SUBURBAN PROPANE PARTNERS LP - Annual Report: 2005 (Form 10-K)

2004. Sales of fuel oil and other refined fuels increased 24.0 million gallons, or 10.9%, to 244.5 million gallons, compared to 220.5 million gallons in the prior fiscal year. The negative impact of warm weather and high energy prices on volumes was partially offset by a full twelve months of Agway Energy operations in fiscal 2005 compared to nine months in fiscal 2004.

For fiscal 2005, we reported a net loss of $8.1 million, or ($0.26) per Common Unit, a decrease of $62.4 million, compared to net income of $54.3 million, or $1.79 per Common Unit, in fiscal 2004. We reported earnings before interest, loss on debt extinguishment, taxes, depreciation and amortization (‘‘EBITDA’’) of $107.1 million for fiscal 2005, a decrease of $24.8 million, or 18.8%, compared to $131.9 million in fiscal 2004.

In addition to the negative impact on our financial results from the fuel oil Ceiling Program, EBITDA and net loss for fiscal 2005 were unfavorably impacted by $3.5 million and $40.9 million, respectively, as a result of certain significant items relating mainly to (i) a $36.2 million loss on debt extinguishment recorded in the third quarter associated with our debt refinancing; (ii) a $2.8 million restructuring charge attributable primarily to severance associated with the realignment of our field operations; (iii) a $0.7 million charge attributable to impairment of goodwill associated with our HVAC segment; (iv) a $0.8 million charge included within amortization expense attributable to the impairment of other intangible assets in our HVAC segment; and (v) $0.4 million included within depreciation expense attributable to impairment of assets affected by the field realignment.

By comparison, EBITDA and net income for fiscal 2004 included the net favorable impact of $8.6 million and $7.6 million, respectively, from certain significant items mainly related to (i) a $26.3 million gain from the sale of 24 customer service centers in the northern and southern central regions of the United States considered to be non-strategic; (ii) a non-cash charge of $6.3 million included within cost of products sold related to the settlement of futures contracts which were marked-to-market under purchase accounting for the Agway Acquisition; (iii) a non-cash pension settlement charge of $5.3 million related to accelerated recognition of actuarial losses in our defined benefit pension plan; (iv) a non-cash charge of $3.2 million attributable to impairment of goodwill related to a small business acquired in 1999; (v) a $2.9 million restructuring charge related to integrating certain field management and back office functions in the northeast; and (vi) a non-cash charge of $1.0 million included within depreciation expense attributable to the write-down of assets to be disposed of as a result of our efforts to integrate certain northeast operations.

While the continued high price environment had a negative impact on our volumes as a result of customer conservation efforts and on the profitability of our refined fuels segment, our propane segment generated solid results despite the challenging environment. Profitability of our propane segment increased $3.5 million, or 2.4%, in fiscal 2005 compared to the prior year. Additionally, during the second half of fiscal 2005, we took positive steps to add financial flexibility and drive further efficiencies throughout our operations, highlighted by the successful completion of our debt refinancing and, more recently, the reorganization of our field operations to streamline our operating footprint and leverage our system infrastructure. In connection with our field realignment, we eliminated approximately 85 positions and have begun to consolidate customer service centers for further cost savings.

As we look ahead to fiscal 2006, with the continued integration of the Agway Energy operations, the operating efficiencies expected from our internal reorganization and the steps already taken to eliminate the fuel oil Ceiling Program, we believe we are well positioned for significant earnings growth in fiscal 2006. Our anticipated cash requirements for fiscal 2006 include: (i) maintenance and growth capital expenditures of approximately $30.0 million; (ii) approximately $40.0 million of interest payments; and, (iii) assuming distributions remain at the current level, approximately $76.6 million of distributions to Common Unitholders and the General Partner. The projected level of capital expenditures for fiscal 2006 is approximately $10.0 million higher than our expected annual level of capital spending in subsequent years, primarily as a result of anticipated spending on system enhancements and facility integration. Additionally, as our field realignment efforts continue into fiscal 2006 we may incur additional restructuring or asset impairment charges. Based on our current estimate of our cash position, availability under the Revolving Credit Agreement (unused borrowing capacity under the working capital facility of $76.3 million at November 28, 2005) and expected cash flow from operating activities, we expect to have sufficient funds to meet our current and future obligations.

19

Results of Operations

Fiscal Year 2005 Compared to Fiscal Year 2004

Revenues

(Dollars in thousands)

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

Total revenues increased $313.0 million, or 23.9%, to $1,620.2 million for the year ended September 24, 2005 compared to $1,307.3 million for the year ended September 25, 2004 driven primarily by a significant increase in average selling prices in line with higher product costs, the inclusion of the Agway Energy operations for a full twelve months in fiscal 2005 compared to nine months in the prior year, offset to an extent by the impact on volumes from warmer weather. Retail sales volumes in our propane and fuel oil segments were negatively impacted by a combination of warmer than normal average nationwide temperatures, as well as the impact of customer conservation efforts from the significant rise in energy costs. As reported by NOAA, average nationwide temperatures in both fiscal 2005 and 2004 were 7% warmer than normal. However, the fiscal 2005 heating season presented a very erratic weather pattern with significantly warmer than normal temperatures during the critical months of the heating season (November 2004 through February 2005) offset somewhat by a burst of cold weather in March 2005. Average nationwide temperatures were 9% warmer than normal during these critical months in fiscal 2005.

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

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

20

---

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

Cost of Products Sold

(Dollars in thousands)

				Fiscal 2005				Fiscal 2004				Increase/ (Decrease)				Percent Increase/ (Decrease)
Cost of products sold
Propane				$	545,649			$	453,869			$	91,780				20.2	%
Fuel oil and refined fuels					383,032				223,362				159,670				71.5	%
Natural gas and electricity					90,461				59,950				30,511				50.9	%
HVAC					42,650				36,267				6,383				17.6	%
All other					5,456				5,581				(125	)			(2.2	%)
Total cost of products sold				$	1,067,248			$	779,029			$	288,219				37.0	%
As a percent of total revenues					65.9	%			59.6	%

The cost of products sold reported in the consolidated statements of operations represents the weighted average unit cost of propane and fuel oil sold, as well as the cost of natural gas and electricity, including transportation costs to deliver product from our supply points to storage or to our customer service centers. Cost of products sold also includes the cost of appliances and related parts sold or installed by our customer service centers computed on a basis that approximates the average cost of the products. Cost of products sold is reported exclusive of any depreciation and amortization; these amounts are reported separately within the consolidated statements of operations.

Cost of products sold increased $288.2 million, or 37.0%, to $1,067.2 million for the year ended September 24, 2005 compared to $779.0 million in the prior year. The increase results primarily from higher commodity prices for propane and fuel oil, coupled with the full year impact of the Agway Energy operations. Cost of products sold associated with the distribution of propane and related activities of $545.6 million increased $91.8 million, or 20.2%, compared to the prior year. Higher propane prices resulted in a $112.3 million increase in cost of products sold during fiscal 2005 compared to the prior year, partially offset by the 4.0% decline in propane volumes which had an impact of $15.9 million. Lower wholesale and risk management activities, noted above, decreased cost of products sold by $3.7 million compared to the prior year.

Cost of products sold associated with our fuel oil and refined fuels segment of $383.0 million for the year ended September 24, 2005 increased $159.7 million, or 71.5%, compared to the prior year. The impact of the unprecedented high commodity prices increased cost of products sold by $134.6 million during fiscal 2005 compared to the prior year and the increased volumes had an impact of $24.3 million. Cost of products sold in the prior year also included a $6.3 million non-cash charge associated with the settlement of futures contracts that were acquired in the Agway Acquisition. As the underlying futures and option contracts were settled, the derivative assets were charged to cost of products sold as an offset to the realized gains from contract settlement. The impact on cost of products sold represented a non-cash charge resulting from the application of purchase accounting on derivative instruments acquired.

While revenues increased 53.1%, margin opportunities and therefore profitability in our fuel oil and refined fuels segment were significantly restricted during our second and third quarters of fiscal 2005 as a result of our fuel oil Ceiling Program. We were unable in the prevailing high price environment to pass on fully the rise in fuel oil prices due to the restrictions of our fuel oil Ceiling Program, which

21

---

pre-established a maximum price per gallon, coupled with our decision not to hedge this pricing program for the February through April deliveries when confronted with unprecedented costs to properly hedge the program during that period. The lost margin opportunity from this fuel oil Ceiling Program had the most significant negative impact on our financial results for fiscal 2005 accounting for an estimated impact of $21.5 million on the year-over-year comparison of operating margins in the fuel oil and refined fuels segment. After evaluating the costs to adequately hedge this program in the current price environment, management decided to discontinue offering the fuel oil Ceiling Program after the fiscal 2005 heating season. Cost of products sold as a percentage of revenues in our fuel oil and refined fuels segment increased from 79.2% during fiscal 2004 to 88.4% in fiscal 2005 primarily as a result of our inability to pass on fully the unprecedented rise in fuel oil prices, coupled with the fact that February through April 2005 deliveries under the Ceiling Program were not hedged as the costs to hedge continued to be prohibitive due to market volatility.

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

For the year ended September 24, 2005, cost of products sold represented 65.9% of revenues compared to 59.6% in the prior year. This increase results primarily from the impact of the fuel oil operations described above, as well as the continued impact of product mix with a full year of the non-propane Agway Energy operations.

Operating Expenses

(Dollars in thousands)

				Fiscal 2005				Fiscal 2004				Increase				Percent Increase
Operating expenses				$	396,235			$	361,696			$	34,539				9.5	%
As a percent of total revenues					24.5	%			27.7	%

All costs of operating our retail distribution and appliance sales and service operations are reported within operating expenses in the consolidated statements of operations. These operating expenses include the compensation and benefits of field and direct operating support personnel, costs of operating and maintaining our vehicle fleet, overhead and other costs of our purchasing, training and safety departments and other direct and indirect costs of our customer service centers. Changes in the fair value of derivative instruments that are not designated as hedges are recorded in current period earnings within operating expenses.

Operating expenses of $396.2 million for the year ended September 24, 2005 increased $34.5 million, or 9.5%, compared to $361.7 million in the prior year. Operating expenses for fiscal 2005 include a $2.5 million unrealized (non-cash) loss representing the net change in fair values of derivative instruments during the period, compared to a $4.5 million unrealized loss in the prior year (see Item 7A in this Annual Report for information on our policies regarding the accounting for derivative instruments). In addition to the non-cash impact of changes in the fair value of derivative instruments, the most significant impact on operating expenses was the increase in employee, vehicle and facility costs reflecting a full year of Agway Energy operations, offset to an extent by expense savings attributable to synergies in our northeast operations and continued expense management, particularly in light of lower operating results. Additionally, fiscal 2004 operating expenses included a $5.3 million non-cash pension charge in order to accelerate the recognition of a portion of unrecognized actuarial losses in our defined benefit pension plan. The accelerated recognition of these losses was recorded in accordance with SFAS No. 88 ‘‘Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits’’ (‘‘SFAS 88’’) as a result of an increase in the level of lump sum benefit payments made to retirees or terminated individuals during fiscal 2004 compared to prior years.

Operating expenses in fiscal 2005 increased primarily in the following areas: (i) employee compensation and benefit costs increased a net $21.1 million related to the impact of the Agway Energy

22

---

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

General and Administrative Expenses

(Dollars in thousands)

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

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

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

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

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

Depreciation and Amortization

(Dollars in thousands)

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

Depreciation and amortization expense for the year ended September 24, 2005 increased $1.0 million, or 2.8%, compared to the prior year primarily as a result of a full year of depreciation and amortization on the tangible and intangible assets acquired in the Agway Acquisition. Depreciation and amortization expense in fiscal 2005 included a $0.4 million asset impairment charge associated with steps

23

---

taken in the fourth quarter to realign our field operations, compared to a $1.0 million asset impairment charge in the prior year. In addition, fiscal 2005 included a non-cash charge of $0.8 million attributable to an impairment in the value of tradenames associated with our HVAC segment which were acquired in the Agway Acquisition.

Interest Expense

(Dollars in thousands)

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

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

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

Net (Loss) Income and EBITDA. We reported a net loss of $8.1 million for the year ended September 24, 2005 compared to net income of $54.3 million in the prior year. Reported EBITDA for fiscal 2005 of $107.1 million decreased $24.8 million, or 18.8%, compared to $131.9 million in the prior year. EBITDA and net loss for fiscal 2005 were unfavorably impacted by $3.5 million and $40.9 million, respectively, as a result of certain significant items relating mainly to (i) a $36.2 million loss on debt extinguishment recorded in the third quarter associated with our debt refinancing; (ii) a $2.8 million restructuring charge attributable primarily to severance associated with the realignment of our field operations; (iii) a $0.7 million charge attributable to impairment of goodwill associated with our HVAC segment; (iv) a $0.8 million charge included within amortization expense attributable to the impairment of other intangible assets in our HVAC segment; and (v) $0.4 million included within depreciation expense attributable to impairment of assets affected by the field realignment. In addition to the non-recurring items impacting fiscal 2005 results, the most significant negative impact on earnings was from the approximate $21.5 million impact on margin opportunities in our fuel oil business from the Ceiling Program. Income before interest expense, loss on debt extinguishment and income taxes in our propane and natural gas and electricity segments improved $3.5 million and $2.3 million, respectively.

By comparison, EBITDA and net income for fiscal 2004 included the net favorable impact of $8.6 million and $7.6 million, respectively, from the following significant items: (i) a $26.3 million gain from the sale of 24 customer service centers in the northern and southern central regions of the United States considered to be non-strategic; (ii) a non-cash charge of $6.3 million included within cost of products sold related to the settlement of futures contracts which were marked-to-market under purchase accounting for the Agway Acquisition; (iii) a non-cash pension settlement charge of $5.3 million related to accelerated recognition of actuarial losses in our defined benefit pension plan; (iv) a non-cash charge of $3.2 million attributable to impairment of goodwill related to a small business acquired in 1999; (v) a $2.9 million restructuring charge related to integrating certain field management and back office functions in the northeast; and (vi) a non-cash charge of $1.0 million included within depreciation expense attributable to the write-down of assets to be disposed of as a result of our efforts to integrate certain northeast operations.

EBITDA represents net income before deducting interest expense, loss on debt extinguishment, income taxes, depreciation and amortization. Our management uses EBITDA as a measure of liquidity

24

---

and we are including it because we believe that it provides our investors and industry analysts with additional information to evaluate our ability to meet our debt service obligations and to pay our quarterly distributions to holders of our Common Units. Moreover, our Revolving Credit Agreement requires us to use EBITDA as a component in calculating our leverage and interest coverage ratios. EBITDA is not a recognized term under GAAP and should not be considered as an alternative to net income 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:

(Dollars in thousands)

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

Fiscal Year 2004 Compared to Fiscal Year 2003

Revenues

(Dollars in thousands)

				Fiscal 2004				Fiscal 2003				Increase				Percent Increase
Revenues
Propane				$	856,109			$	680,840			$	175,269				25.7	%
Fuel oil and refined fuels					281,682				—				281,682				100	%
Natural gas and electricity					68,452				—				68,452				100	%
HVAC					92,072				46,938				45,134				96.2	%
All other					8,939				7,297				1,642				22.5	%
Total revenues				$	1,307,254			$	735,075			$	572,179				77.8	%

Total revenues increased $572.2 million, or 77.8%, to $1,307.3 million for the year ended September 25, 2004 compared to $735.1 million for the year ended September 27, 2003 driven primarily by the Agway

25

---

Acquisition. Revenues in our propane segment of $856.1 million for the year ended September 25, 2004 increased $175.3 million, or 25.7%, compared to $680.8 million in the prior year. This increase is the result of higher retail and wholesale 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 8% warmer than the prior year, retail propane gallons sold increased 45.8 million gallons, or 9.3%, to 537.3 million gallons for the year ended September 25, 2004. The increase is primarily attributable to the addition of Agway Energy volumes from December 23, 2003, partially offset by the effect of the warmer temperatures. Average selling prices increased approximately 12.5% as a result of sustained higher commodity prices for propane. The average posted price of propane during fiscal 2004 increased approximately 23% compared to the average posted prices in the prior year. Additionally, included within the propane segment are revenues from wholesale and risk management activities of $43.0 million for the year ended September 25, 2004 which increased $26.4 million, compared to the prior year.

Revenue contribution from our fuel oil and other refined fuels and our natural gas and electricity segments amounted to $281.7 million and $68.5 million, respectively, for the year ended September 25, 2004 from the addition of Agway Energy since December 23, 2003. Total fuel oil and other refined fuel gallons sold in fiscal 2004 amounted to 220.5 million gallons. Revenues from our HVAC service and installation activities, as well as from sales of HVAC equipment and related parts, of $92.1 million for the year ended September 25, 2004 increased $45.1 million compared to the prior year, primarily due to the addition of Agway Energy.

Cost of Products Sold

(Dollars in thousands)

				Fiscal 2004				Fiscal 2003				Increase				Percent Increase
Cost of products sold
Propane				$	453,869			$	332,132			$	121,737				36.7	%
Fuel oil and refined fuels					223,362				—				223,362				100	%
Natural gas and electricity					59,950				—				59,950				100	%
HVAC					36,267				22,035				14,232				64.6	%
All other					5,581				4,415				1,166				26.4	%
Total cost of products sold				$	779,029			$	358,582			$	420,447				117.3	%
As a percent of total revenues					59.6	%			48.8	%

Cost of products sold increased $420.4 million to $779.0 million for the year ended September 25, 2004 compared to $358.6 million in the prior year. 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 $246.2 million on the year-over-year comparison of cost of products sold. Higher commodity prices for propane during fiscal 2004 also increased cost of products sold by $65.9 million compared to the prior year. Increased wholesale and risk management activities, noted above, increased cost of products sold by $26.7 million compared to the prior year.

Cost of products sold for the year ended September 25, 2004 also included a $6.3 million non-cash charge associated with the settlement of futures contracts that were acquired in the Agway Acquisition. As the underlying futures and option contracts were settled, the derivative assets were charged to cost of products sold as an offset to the realized gains from contract settlement. The impact on cost of products sold represents a non-cash charge resulting from the application of purchase accounting on derivative instruments acquired. In addition, the increase in revenues attributable to our natural gas and electricity and HVAC business segments had a $60.0 million and $14.2 million impact, respectively, on cost of products sold in the year ended September 25, 2004 compared to the prior year.

For the year ended September 25, 2004, cost of products sold represented 59.6% of revenues compared to 48.8% in the prior year. This increase results primarily from the different mix of products sold

26

---

during fiscal 2004 as a result of the additional product offerings from the Agway Energy operations. Generally, the prices for fuel oil and other refined fuels as a percentage of product revenues tend to be between 20% and 30% higher than propane costs are as a percentage of propane revenues.

Operating Expenses

(Dollars in thousands)

				Fiscal 2004				Fiscal 2003				Increase				Percent Increase
Operating expenses				$	361,696			$	232,462			$	129,234				55.6	%
As a percent of total revenues					27.7	%			31.6	%

Operating expenses of $361.7 million for the year ended September 25, 2004 increased $129.2 million, or 55.6%, compared to $232.5 million in the prior year. Operating expenses for fiscal 2004 include a $4.5 million unrealized (non-cash) loss representing the net change in fair values of derivative instruments during the period, compared to a $1.5 million unrealized loss in the prior year (see Item 7A in this Annual Report for information on our policies regarding the accounting for derivative instruments). In addition to the non-cash impact of changes in the fair value of derivative instruments, the most significant impact on operating expenses was the impact on employee, vehicle and facility costs from the addition of the Agway Energy operations. Additionally, fiscal 2004 operating expenses include a $5.3 million non-cash pension charge in order to accelerate the recognition of a portion of unrecognized actuarial losses in our defined benefit pension plan. The accelerated recognition of these losses was a result of an increase in the level of lump sum benefit payments made to retirees or terminated individuals during fiscal 2004 compared to prior years.

Operating expenses in fiscal 2004 increased primarily in the following areas: (i) employee compensation and benefit costs increased $51.6 million related to an increase in field personnel and increased earnings; (ii) costs to operate our fleet increased $9.2 million; (iii) operating costs at our customer service centers increased $42.0 million as a result of the addition of the Agway Energy operations; (iv) pension costs increased $7.4 million primarily as a result of the $5.3 million non-cash charge described above; (iv) insurance costs increased $13.2 million; and, (v) medical costs increased $2.9 million.

General and Administrative Expenses

(Dollars in thousands)

				Fiscal 2004				Fiscal 2003				Increase				Percent Increase
General and administrative expenses				$	53,888			$	36,661			$	17,227				47.0	%
As a percent of total revenues					4.1	%			5.0	%

General and administrative expenses of $53.9 million for the year ended September 25, 2004 were $17.2 million, or 47.0%, higher compared to $36.7 million in fiscal 2003. The increase was primarily attributable to the impact of $10.4 million higher employee compensation and benefit costs as a result of higher earnings 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 Agway Acquisition. In addition, we incurred anticipated increases in marketing, professional services and travel expenses during fiscal 2004 associated with our efforts to acquire Agway Energy during the first quarter and in connection with our integration efforts during the remainder of fiscal 2004.

Restructuring Costs and Impairment of Goodwill. During fiscal 2004, we recorded a $2.9 million restructuring charge for severance and other exit costs associated with vacating duplicative facilities and contract terminations in connection with the integration of Agway Energy operations and management. While the majority of restructuring and integration activities were completed by the end of fiscal 2004, there may be additional charges in fiscal 2005 as we continue to finalize our operating footprint in the northeast. Additionally, during the third quarter of fiscal 2004, as a result of continued losses in one of our reporting units acquired in fiscal 1999, we recorded a non-cash charge of $3.2 million related to goodwill impairment.

27

---

Depreciation and Amortization

(Dollars in thousands)

				Fiscal 2004				Fiscal 2003				Increase				Percent Increase
Depreciation and amortization				$	36,743			$	27,520			$	9,223				33.5	%
As a percent of total revenues					2.8	%			3.7	%

Depreciation and amortization expense increased 33.5% to $36.7 million for the year ended September 25, 2004 compared to $27.5 million for the prior year, primarily as a result of the additional depreciation and amortization associated with the acquired tangible and intangible assets from the Agway Acquisition. In addition, depreciation expense for fiscal 2004 included a $1.0 million non-cash charge related to assets abandoned as a result of our facility integration efforts in the northeast.

Interest Expense

(Dollars in thousands)

				Fiscal 2004				Fiscal 2003				Increase				Percent Increase
Interest expense, net				$	40,832			$	33,629			$	7,203				21.4	%
As a percent of total revenues					3.1	%			4.6	%

Net interest expense increased $7.2 million, or 21.4%, to $40.8 million for the year ended September 25, 2004, compared to $33.6 million in the prior year. The increase results primarily from the net impact of the addition of $175.0 million of 6.875% senior notes associated with financing for the Agway Acquisition, offset by a reduction in amounts outstanding under our 7.54% senior notes due to repayment of the second annual principal payment of $42.5 million during the fourth quarter of fiscal 2003 and of the third annual principal payment of $42.5 million during the fourth quarter of fiscal 2004, in both cases using cash on hand. In addition, we incurred a one-time fee of $1.9 million related to financing commitments for the Agway Acquisition during the first quarter of fiscal 2004 which is included within fiscal 2004 interest expense.

Discontinued Operations. During fiscal 2004, we sold 24 customer service centers for net cash proceeds of $39.4 million. We recorded a gain on sale of $26.3 million during fiscal 2004. During fiscal 2003, we sold nine customer service centers for net cash proceeds of $7.2 million and recorded a gain on sale of $2.5 million. Gains on sale have been accounted for within discontinued operations in accordance with SFAS 144.

Net Income and EBITDA. Net income of $54.3 million for the year ended September 25, 2004 increased $5.6 million, or 11.5%, compared to $48.7 million in the prior year. We reported record EBITDA of $131.9 million for the year ended September 25, 2004, compared to $110.0 million for the prior year, an increase of $21.9 million, or 19.9%. Net income and EBITDA for fiscal 2004 were favorably impacted by the net result of certain significant items, mainly relating to: (i) the $26.3 million gain from the sale of 24 customer service centers considered to be non-strategic, primarily located in the northern and southern central regions of the United States, compared to a $2.5 million gain from the sale of nine customer service centers during fiscal 2003; (ii) the non-cash charge of $6.3 million included within cost of products sold relating to the settlement of futures contracts which were marked-to-market under purchase accounting for the Agway Acquisition; (iii) the non-cash pension charge of $5.3 million related to accelerated recognition of actuarial losses as a result of the level of lump sum benefit payments in fiscal 2004; (iv) the non-cash charge of $3.2 million attributable to the impairment of goodwill related to a small business acquired in 1999; (v) the $2.9 million restructuring charge related to our efforts to integrate certain management and back office functions of Agway Energy; and, (vi) the non-cash charge of $1.0 million included within depreciation expense attributable to the write-down of assets to be disposed of as a result of the blending of field operations in the northeast. These significant items had a net positive impact of $6.1 million and $5.1 million on the year-over-year comparison of EBITDA and net income, respectively, for the year ended September 25, 2004.

Our management uses EBITDA as a measure of liquidity and we are including it because we believe that it provides our investors and industry analysts with additional information to evaluate our ability to

28

---

meet our debt service obligations and to pay our quarterly distributions to holders of our Common Units. Moreover, our Revolving Credit Agreement requires us to use EBITDA as a component in calculating our leverage and interest coverage ratios. EBITDA is not a recognized term under GAAP and should not be considered as an alternative to net income 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:

(Dollars in thousands)

				Year Ended
				September 25, 2004				September 27, 2003
Net income				$	54,304			$	48,669
Add:
Provision for income taxes					3				202
Interest expense, net					40,832				33,629
Depreciation and amortization					36,743				27,520
EBITDA					131,882				110,020
Add (subtract):
Provision for income taxes					(3	)			(202	)
Interest expense, net					(40,832	)			(33,629	)
Gain on disposal of property, plant and equipment, net					(715	)			(636	)
Gain on sale of customer service centers					(26,332	)			(2,483	)
Changes in working capital and other assets and liabilities					29,065				(15,770	)
Net cash provided by (used in)
Operating activities				$	93,065			$	57,300
Investing activities				$	(196,557	)		$	(4,859	)
Financing activities				$	141,208			$	(77,631	)

Liquidity and Capital Resources

Analysis of 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 propane purchased during the heating season. Net cash provided by operating activities for the year ended September 24, 2005 amounted to $39.0 million, a decrease of $54.1 million, or 58.1%, compared to $93.1 million in the prior year. The decrease was attributable to a $65.3 million increased investment in working capital in comparison to the prior year, particularly in increased accounts receivable balances as a result of the significant rise in commodity prices, coupled with $8.1 million lower income, after adjusting for non-cash items in both periods (depreciation, amortization, loss on debt extinguishment and gains on disposal of assets and customer service centers); offset to an extent by an increase in other long-term assets and liabilities of $19.3 million. The continued high commodity price environment in both propane and fuel oil has resulted in a significant increase in average selling prices and, in turn, higher receivable balances in relation to the prior year, as well as higher average inventory costs.

In fiscal 2004, net cash provided by operating activities increased $35.8 million, or 62.5%, to $93.1 million, compared to $57.3 million in fiscal 2003. The increase was primarily due to improved net income, as well as a decrease in net working capital investment compared to the prior year. Net working capital decreased primarily as a result of an increase in customer prepayments and deposits under our budget payment programs, particularly in our fuel oil and other refined fuels segment. Under these budget

29

---

payment programs, customers pay equal monthly installments beginning in June or July for the upcoming heating season based on each customer’s historical usage patterns.

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

Net cash used in investing activities of $196.6 million for the year ended September 25, 2004 consisted of the net impact of the $211.2 million total cost of the Agway Acquisition partially offset by net proceeds of $39.4 million from the sale of customer service centers during fiscal 2004 and net proceeds of $1.8 million from the sale of property, plant and equipment. Additionally, capital expenditures were $26.5 million (including $7.4 million for maintenance expenditures and $19.1 million to support the growth of operations) for fiscal 2004. Capital spending in fiscal 2004 increased $12.4 million, or 87.9%, compared to fiscal 2003 primarily as a result of our facility integration efforts in the northeast, as well as additional spending on information technology in connection with the integration of Agway Energy.

Financing Activities.    Net cash used in financing activities for the year ended September 24, 2005 of $53.4 million reflects the impact of the March 31, 2005 debt refinancing which included the early retirement of $340.0 million of private placement senior notes and a related prepayment premium of $32.0 million, offset by net proceeds of $373.0 million, net of a discount, from the issuance of an additional $250.0 million of 6.875% senior notes due 2013 (bringing the total principal amount of such notes to $425.0 million) and borrowings of $125.0 million under our new Term Loan (see Summary of Long-Term Debt Obligations and Revolving Credit Lines below). In addition, we had borrowings of $26.8 million under our Revolving Credit Agreement in order to fund increased working capital needs during the heating season, offset by $4.2 million in fees associated with closing of the March 31, 2005 debt refinancing and the Third Amended and Restated Credit Agreement in October 2004. Quarterly distributions to holders of our Common Units and the General Partner at a rate $0.6125 per Common Unit for each quarter of fiscal 2005 amounted to $76.6 million.

Net cash provided by financing activities for the year ended September 25, 2004 was $141.2 million as a result of: (i) net proceeds of $169.1 million from the issuance of $175.0 million aggregate principal amount of 6.875% senior notes due 2013, a portion of which was used to fund a portion of the Agway Acquisition; and, (ii) net proceeds of $87.6 million from a public offering of approximately 3.0 million Common Units (including full exercise of the underwriters’ over-allotment option) during December 2003 to fund a portion of the Agway Acquisition; offset by: (i) the payment of a total of $72.5 million for our quarterly distributions of $0.5875 per Common Unit during each of the first two quarters of fiscal 2004, $0.60 per Common Unit during the third quarter of fiscal 2004 and $0.6125 per Common Unit during the fourth quarter of fiscal 2004; and, (ii) the repayment of the third annual principal installment of $42.5 million due under the 1996 Senior Note Agreement (which was terminated as a result of the Refinancing).

Summary of Long-Term Debt Obligations and Revolving Credit Lines

On October 20, 2004, our Operating Partnership executed the Third Amended and Restated Credit Agreement (the ‘‘Revolving Credit Agreement’’), which replaced the Second Amended and Restated Credit Agreement then due to expire in May 2006. The Revolving Credit Agreement extended the maturity to October 20, 2008 and provided available credit of $150.0 million in the form of a $75.0 million revolving working capital facility, of which $15.0 million could be used to issue letters of credit, and a separate $75.0 million letter of credit facility. The Second Amended and Restated Credit Agreement provided a $75.0 million working capital facility and a $25.0 million acquisition facility. In connection with the Revolving Credit Agreement, our permitted leverage ratio (the ratio of total debt to EBITDA) was reduced from a ratio of 5.0 to 1 to a ratio of less than 4.5 to 1.

On March 31, 2005, we completed a refinancing (the ‘‘Refinancing’’) of our Operating Partnership’s $297.5 million outstanding principal amount of 1996 Senior Notes due 2011 and $42.5 million outstanding

30

---

principal amount of 2002 Senior Notes due 2012 (collectively, the ‘‘Redeemed Notes’’). Under the Refinancing, we issued $250.0 million of additional notes under the indenture governing our 2003 Senior Notes and received proceeds of approximately $246.9 million, net of a $2.0 million discount on sale and related underwriter fees. In addition, our Operating Partnership entered into the first amendment to the Revolving Credit Agreement to provide, among other things, for a five-year $125.0 million term loan facility (the ‘‘Term Loan’’). The total net proceeds of approximately $371.9 million from the issuance of additional senior notes under the indenture governing the 2003 Senior Notes and from the $125.0 million of borrowings under the Term Loan, together with cash of approximately $7.3 million, were used to prepay the Redeemed Notes, including a prepayment premium of approximately $32.0 million and interest accrued on the Redeemed Notes of approximately $6.4 million from the last interest payment date through the date of redemption.

The Redeemed Notes required an annual principal repayment of $42.5 million through 2012. The Refinancing replaced the annual cash requirement for principal amortization with the $125.0 million five-year Term Loan due 2010 and the $250.0 million of additional 2003 Senior Notes due 2013, significantly extending our debt maturities and eliminating refinancing risk associated with the amortization of the Redeemed Notes. The Refinancing is expected to reduce our annual interest expense for at least the next five years. We recorded a one-time charge of $36.2 million for the year ended September 24, 2005 as a result of the Refinancing to reflect the loss on debt extinguishment associated with the prepayment premium of $32.0 million and the write-off of $4.2 million of unamortized bond issuance costs associated with the Redeemed Notes.

As a result of the Refinancing, we eliminated our requirement under the Redeemed Notes to maintain a leverage ratio and an interest coverage ratio without adding a comparable financial covenant under the 2003 Senior Notes. As a result of the first amendment to the Revolving Credit Agreement, our Operating Partnership’s permitted leverage ratio was reduced from a ratio of 4.5 to 1 to a ratio of less than 4.0 to 1 and the interest coverage ratio (the ratio of EBITDA to interest expense) was amended to require maintenance of a ratio of greater than 2.5 to 1 on a consolidated basis. The Revolving Credit Agreement and the 2003 Senior Notes both contain various restrictive and affirmative covenants applicable to our Operating Partnership and us, respectively; including (i) restrictions on the incurrence of additional indebtedness, and (ii) restrictions on certain liens, investments, guarantees, loans, advances, payments, mergers, consolidations, distributions, sales of assets and other transactions. We were in compliance with all covenants and terms of all of our debt agreements as of September 24, 2005 and as of the end of each fiscal quarter for all periods presented.

On August 26, 2005, we completed the second amendment to the Revolving Credit Agreement pursuant to which the lenders (i) eliminated the stand-alone $75.0 million letter of credit facility and combined that credit with the existing revolving working capital facility; (ii) increased the revolving working capital facility by an additional $25.0 million, thereby raising the amount of the working capital facility from $75.0 million to $175.0 million (including the $75.0 million from the former stand-alone letter of credit facility); (iii) extended the revolving credit facility’s expiration date to match the March 31, 2010 maturity date of the $125.0 million Term Loan; and, (iv) amended certain other terms to effect the foregoing. All other terms and conditions under the Revolving Credit Agreement remained the same. As of September 24, 2005, there was $26.8 million outstanding under the working capital facility of the Revolving Credit Agreement that was used to fund working capital requirements.

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

Borrowings under the Revolving Credit Agreement, including the Term Loan, bear interest at a rate based upon either LIBOR or Wachovia National Bank's prime rate, plus, in each case, the applicable margin or the Federal Funds rate plus 1/2 of 1%. An annual facility fee ranging from 0.375% to 0.50%, based upon certain financial tests, is payable quarterly whether or not borrowings occur.

31

---

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 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 our Second Amended and Restated Partnership Agreement (the ‘‘Partnership Agreement’’), approximately 45 days after the end of each fiscal quarter to holders of record on the applicable record dates. Our Board of Supervisors reviews the level of Available Cash on a quarterly basis based upon information provided by management. During fiscal 2005, we paid quarterly distributions to our Common Unitholders of $0.6125 per Common Unit. On October 20, 2005, our Board of Supervisors declared a quarterly distribution of $0.6125 per Common Unit in respect of the fourth quarter of fiscal 2005, which was paid on November 8, 2005 to holders of record on November 1, 2005.

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 majority-owned by senior 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. 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.

Pension Plan Assets and Obligations

While our pension asset portfolio has experienced significantly improved asset returns over the past three fiscal years, the funded status of our defined benefit pension plan continues to be affected by the negative impact of the low interest rate environment on the actuarial value of the projected benefit obligations, as well as the cumulative impact of prior losses particularly during fiscal 2002 and fiscal 2001. The projected benefit obligation as of September 24, 2005 exceeded the market value of pension plan assets by $40.2 million, an increase of $5.2 million compared to the $35.0 million underfunded position at the end of the prior year.

Our defined benefit pension plan was frozen to new participants effective January 1, 2000 and, in furtherance of our effort to minimize future increases in our benefit obligations, effective January 1, 2003, all future service credits were eliminated. Therefore, eligible participants will receive interest credits only toward their ultimate defined benefit under the defined benefit pension plan. There were no minimum funding requirements for the defined benefit pension plan during fiscal 2005, 2004 or 2003. However, in an effort to proactively address our funded status, we elected to make voluntary contributions to our defined benefit pension plan of $15.1 million and $10.0 million during fiscal 2004 and fiscal 2003, respectively. These voluntary contributions, coupled with improved asset returns in our pension asset portfolio during fiscal 2005, fiscal 2004 and fiscal 2003, partially offset the negative effects on the funded status of further declines in the interest rate environment.

In addition, during fiscal 2004 lump sum benefit payments to either terminated or retired individuals of $12.3 million exceeded the interest cost component of the net periodic pension cost. As a result, pursuant to SFAS 88 we recorded a non-cash settlement charge of $5.3 million in order to accelerate recognition of a portion of cumulative unrecognized losses in the defined benefit pension plan. These unrecognized losses were previously accumulated as a reduction to partners’ capital and were being amortized to expense as part of our net periodic pension cost in accordance with SFAS No. 87 ‘‘Employers’ Accounting for Pensions.’’ As of September 24, 2005, the cumulative reduction to partners’

32

---

capital decreased to $75.7 million, compared to $76.9 million at the end of fiscal 2004, primarily as a result of continued strength in our asset portfolio returns, offset to an extent by lower benchmark interest rates. The cumulative reduction to partners’ capital is attributable to the level of unrealized losses experienced on our pension assets over the past several years and represents non-cash charges to our partners’ capital with no impact on the results of operations for the year ended September 24, 2005. Additional pension settlement charges may be required in future periods depending on the level of lump sum benefit payments.

There can be no assurance that future declines in capital markets, or interest rates, will not have an adverse impact on our results of operations or cash flow. For purposes of computing the actuarial valuation of projected benefit obligations, we reduced the discount rate assumption from 5.50% as of September 25, 2004 to 5.25% as of September 24, 2005 to reflect current market expectations related to long-term interest rates and the projected duration of our pension obligations based on a benchmark index with similar characteristics as the expected cash flow requirements of our defined benefit pension plan over the long-term. Additionally, for purposes of the computation of the periodic pension cost for fiscal 2005, 2004 and 2003 we assumed declining long-term rates of return on plan assets of 7.50%, 7.75% and 8.50%, respectively, based on the investment mix of our pension asset portfolio, historical asset performance and expectations for future performance. There are currently no minimum funding requirements projected for fiscal 2006 and, based on information provided by our actuaries, we do not project any minimum funding requirements until fiscal 2009.

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

Long-Term Debt Obligations and Operating Lease Obligations

Contractual Obligations

Long-term debt obligations and future minimum rental commitments under noncancelable operating lease agreements as of September 24, 2005 are due as follows:

(Dollars in thousands)

				Fiscal 2006				Fiscal 2007				Fiscal 2008				Fiscal 2009				2010 and thereafter				Total
Long-term debt				$	27,225			$	—			$	—			$	—			$	548,070			$	575,295
Operating leases					20,295				15,096				10,688				5,856				5,814				57,749
Total long-term debt obligations and lease commitments				$	47,520			$	15,096			$	10,688			$	5,856			$	553,884			$	633,044

Additionally, we have standby letters of credit in the aggregate amount of $53.0 million, in support of retention levels under our casualty insurance programs and certain lease obligations, which expire periodically through October 25, 2006.

Off-Balance Sheet Arrangements

Operating Leases

We lease certain property, plant and equipment for various periods under noncancelable operating leases, including the majority of our railroad tank cars, approximately 69% of our vehicle fleet, approximately 26% of our customer service centers and portions of our information systems equipment.

33

---

Rental expense under operating leases was $28.6 million, $27.3 million and $24.3 million for fiscal years 2005, 2004 and 2003, respectively. Future minimum rental commitments under noncancelable operating lease agreements as of September 24, 2005 are presented in the table above.

Guarantees

We have residual value guarantees associated with certain of our operating leases, related primarily to transportation equipment, with remaining lease periods scheduled to expire periodically through fiscal 2012. Upon completion of the lease period, we guarantee that the fair value of the equipment will equal or exceed the guaranteed amount, or we will pay the lessor the difference. Although the fair value of equipment at the end of its lease term has historically exceeded the guaranteed amounts, the maximum potential amount of aggregate future payments we could be required to make under these leasing arrangements, assuming the equipment is deemed worthless at the end of the lease term, is approximately $18.1 million. Of this amount, the fair value of residual value guarantees for operating leases entered into after December 31, 2002 is reflected in other liabilities, with a corresponding amount included within other assets in the accompanying consolidated balance sheet totaling $6.3 million and $3.7 million as of September 24, 2005 and September 25, 2004, respectively.

Recently Issued Accounting Standards

In March 2005, the Financial Accounting Standards Board (‘‘FASB’’) issued FASB Interpretation No. 47, ‘‘Accounting for Conditional Asset Retirement Obligations’’ (‘‘FIN 47’’). FIN 47 clarifies 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 beginning with 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.

In December 2004, the FASB issued a revised SFAS No. 123, ‘‘Share-Based Payment’’ (‘‘SFAS 123R’’). SFAS 123R is a revision of SFAS No. 123 ‘‘Accounting for Stock-Based Compensation’’ and supersedes APB Opinion No. 25 ‘‘Accounting for Stock Issued to Employees’’. SFAS 123R requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant date fair value of the award. SFAS 123R eliminates the alternative of using the APB Opinion No. 25 intrinsic value method of accounting that was provided for in SFAS No. 123 as originally issued and requires that the compensation cost relating to share-based payment transactions be recognized in the financial statements. SFAS 123R is effective beginning with the Partnership’s fiscal year ending September 30, 2006. The Partnership has historically recognized unearned compensation associated with awards of equity instruments ratably to expense over the vesting period (see Note 10). Accordingly, adoption of SFAS 123R is not expected to have an impact on the Partnership’s consolidated financial position, results of operation or cash flows.

34

---

ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

As of September 24, 2005, 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; the writer of an option contract must fulfill the obligation of the option contract, should the holder choose to exercise the option. At expiration, the contracts are settled by the delivery of the product to the respective party or are settled by the payment of a net amount equal to the difference between the then current price and the fixed contract price. The contracts are entered into in anticipation of market movements and to manage and hedge exposure to fluctuating prices of propane and fuel oil, as well as to help ensure the availability of product during periods of high demand.

Market Risk

We are subject to commodity price risk to the extent that propane or fuel oil market prices deviate from fixed contract settlement amounts. Futures traded with brokers 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 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 (loss)/income (‘‘OCI’’) until the hedged item is recognized in earnings. At September 24, 2005, the fair value of the interest rate swap was $1.3 million and was included within other liabilities.

Derivative Instruments and Hedging Activities

We account for derivative instruments in accordance with the provisions of SFAS No. 133, ‘‘Accounting for Derivative Instruments and Hedging Activities,’’ as amended by SFAS No. 137, SFAS No. 138 and SFAS No. 149 (‘‘SFAS 133’’). All derivative instruments are reported on the balance sheet, within other current assets or other current liabilities, at their fair values. Fair values for forward contracts and futures are derived from quoted market prices for similar instruments traded on the NYMEX. On the date that futures, forward and option contracts are entered into, we make a determination as to whether the derivative instrument qualifies for designation as a hedge. Changes in the fair value of derivative instruments are recorded each period in current period earnings or OCI, depending on whether a derivative instrument is designated as a hedge and, if it is, the type of hedge. For derivative instruments

35

---

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 operating expenses. 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 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. We do not include the time value of option contracts in our assessment of hedge effectiveness and, therefore, record changes in the time value component of the options currently in earnings.

At September 24, 2005, the fair value of derivative instruments described above resulted in derivative assets of $0.6 million included within prepaid expenses and other current assets and derivative liabilities of $7.9 million included within other current liabilities. For the year ended September 24, 2005 operating expenses include unrealized (non-cash) losses of $2.5 million compared to unrealized (non-cash) losses of $4.5 million for the year ended September 25, 2004, attributable to the change in the fair value of derivative instruments not designated as hedges. As of September 24, 2005, there were no unrealized gains or losses attributable to commodity hedging transaction included within OCI.

Sensitivity Analysis

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

	A.	The actual fixed contract price of open positions as of September 24, 2005 for each of the future periods.

	B.	The estimated future market prices for futures and forward contracts as of September 24, 2005 as derived from the NYMEX for traded propane or fuel oil futures for each of the future periods.

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

Based on the sensitivity analysis described above, the hypothetical 10% adverse change in market prices for each of the future months for which a future, forward and/or option contract exists indicate a reduction in potential future gains of $3.0 million as of 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. The average posted price of propane on September 24, 2005 at Mont Belvieu, Texas (a major storage point) was $1.1638 per gallon as compared to $0.8225 per gallon on September 25, 2004. The average posted price of fuel oil on September 24, 2005 at Linden, New Jersey was $1.909 per gallon as compared to $1.36 per gallon on September 25, 2004. Since the end of fiscal 2005, both propane and fuel oil average posted prices have declined approximately 15% to $0.9788 per gallon and $1.614 per gallon, respectively, on November 28, 2005.

As of September 24, 2005, our open position portfolio reflected a net short position (sell contracts) aggregating $22.3 million.

36

---

ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Our Consolidated Financial Statements and the Report of Independent Registered Public Accounting Firm thereon and the Supplemental Financial Information listed on the accompanying Index to Financial Statement Schedule are included herein.

Selected Quarterly Financial Data

Due to the seasonality of the retail propane business, our first and second quarter revenues and earnings are consistently greater than third and fourth quarter results. The following presents our selected quarterly financial data for the last two fiscal years (unaudited; in thousands, except per unit amounts).

				First Quarter				Second Quarter				Third Quarter				Fourth Quarter				Total Year
Fiscal 2005
Revenues				$	424,046			$	587,369			$	327,180			$	281,639			$	1,620,234
Income (loss) before interest expense, loss on debt extinguishment and provision for income taxes (a)					34,853				75,070				(13,589	)			(27,967	)			68,367
Income (loss) from continuing operations (a)					24,901				64,481				(59,912	)			(38,522	)			(9,052	)
Discontinued operations:
Gain on sale of customer service centers (b)					—				976				—				—				976
Net income (loss) (a)					24,901				65,457				(59,912	)			(38,522	)			(8,076	)
Income (loss) from continuing operations per common unit – basic					0.77				1.89				(1.92	)			(1.23	)			(0.29	)
Net income (loss) per common unit – basic (c)					0.77				1.91				(1.92	)			(1.23	)			(0.26	)
Net income (loss) per common unit – diluted (c)					0.77				1.90				(1.92	)			(1.23	)			(0.26	)
Cash provided by (used in)
Operating activities					(29,627	)			7,531				44,383				16,718				39,005
Investing activities					(7,909	)			(5,035	)			(6,182	)			(5,505	)			(24,631	)
Financing activities					(96	)			(1,443	)			(43,895	)			(8,010	)			(53,444	)
EBITDA (e)				$	43,972			$	85,244			$	(4,393	)		$	(17,718	)		$	107,105
Retail gallons sold
Propane					141,780				199,124				98,008				77,128				516,040
Fuel oil and refined fuels					65,906				92,886				48,468				37,276				244,536
Fiscal 2004 (d)
Revenues				$	215,572			$	567,324			$	279,694			$	244,664			$	1,307,254
Income (loss) before interest expense and income taxes (a)					29,972				88,518				(14,057	)			(34,654	)			69,779
Income (loss) from continuing operations (a)					20,178				77,665				(24,321	)			(44,578	)			28,944
Discontinued operations:
Gain on sale of customer service centers (b)					—				14,205				619				11,508				26,332
(Loss) income from discontinued customer service centers					(87	)			690				(635	)			(940	)			(972	)
Net income (loss) (a)					20,091				92,560				(24,337	)			(34,010	)			54,304
Income (loss) from continuing operations per common unit – basic					0.70				2.26				(0.78	)			(1.43	)			0.96
Net income (loss) per common unit – basic (c)					0.70				2.68				(0.78	)			(1.09	)			1.79
Net income (loss) per common unit – diluted (c)					0.70				2.67				(0.78	)			(1.09	)			1.78
Cash provided by (used in)
Operating activities					11,561				11,773				77,902				(8,171	)			93,065
Investing activities					(214,995	)			15,355				(4,464	)			7,547				(196,557	)
Financing activities					240,315				(18,348	)			(19,093	)			(61,666	)			141,208
EBITDA (e)				$	37,114			$	112,636			$	(4,896	)		$	(12,972	)		$	131,882
Retail gallons sold
Propane					131,917				219,945				99,492				85,976				537,330
Fuel oil and refined fuels					8,058				104,157				60,298				47,956				220,469

37

---

(a)	These amounts include, in addition to the gain on sale of customer service centers, gains from the disposal of property, plant and equipment of $2.0 million for fiscal 2005 and $0.7 million for fiscal 2004.

(b)

Gain on sale of customer service centers recorded in the second quarter of fiscal 2005 reflects a $1.0 million finalization of certain purchase price adjustments with the buyer of the customer service centers sold in fiscal 2004. Gain on sale of customer service centers for fiscal 2004 reflects the sale of ten customer service centers during the second quarter for net cash proceeds of approximately $22.9 million, one customer service center we sold during the third quarter for net cash proceeds of approximately $0.9 million and 13 customer service centers we sold during the fourth quarter for net cash proceeds of approximately $15.6 million. We recorded a gain on sale in the second, third and fourth quarters of fiscal 2004 of approximately $14.1 million, $0.6 million and $11.6 million, respectively. Gains on sale of assets have been accounted for within discontinued operations pursuant to SFAS 144.

(c)

Basic net income (loss) per Common Unit is computed by dividing net income (loss), after deducting our general partner's interest, by the weighted average number of outstanding Common Units. Diluted net income per Common Unit is computed by dividing net income, after deducting our general partner's approximate 3.1% interest, by the weighted average number of outstanding Common Units and time vested restricted units granted under our 2000 Restricted Unit Plan. On March 31, 2004, the Emerging Issues Task Force (‘‘EITF’’) reached a consensus under EITF 03-6 ‘‘Participating Securities and the Two-Class Method Under FAS 128’’ (‘‘EITF 03-6’’) which requires, among other things, the use of the two-class method of computing earnings per unit when participating securities exist. The two-class method is an earnings allocation formula that computes earnings per unit for each class of Common Unit and participating security according to distributions declared and participation rights in undistributed earnings, as if all of the earnings were distributed to the limited partners and the general partner (inclusive of the IDRs which are considered participating securities for purposes of the application of EITF 03-6). We adopted EITF 03-6 at the end of fiscal 2004; however, the application of its consensus on the computation of our net income per Common Unit for the years ended September 24, 2005 or September 25, 2004 did not have any impact on annual net income per Common Unit. The requirements of EITF 03-6 do not apply to the computation of net income per Common Unit in periods in which a net loss is reported. Net income and income from continuing operations per Common Unit presented in this table for the first and second quarters of fiscal 2005 and 2004 reflect the impact of the application of EITF 03-6.

(d)	Includes the results from our acquisition of substantially all of the assets and liabilities of Agway Energy from December 23, 2003, the date of acquisition.

(e)

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

38

---

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

Fiscal 2004				First Quarter				Second Quarter				Third Quarter				Fourth Quarter				Total Year
Net income (loss)				$	20,091			$	92,560			$	(24,337	)		$	(34,010	)		$	54,304
Add:
Provision (benefit) for income taxes					83				83				(283	)			120				3
Interest expense, net					9,711				10,770				10,547				9,804				40,832
Depreciation and amortization					7,229				9,223				9,177				11,114				36,743
EBITDA					37,114				112,636				(4,896	)			(12,972	)			131,882
Add (subtract):
(Provision) benefit for income taxes					(83	)			(83	)			283				(120	)			(3	)
Interest expense, net					(9,711	)			(10,770	)			(10,547	)			(9,804	)			(40,832	)
(Gain) loss on disposal of property, plant and equipment, net					(82	)			(79	)			8				(562	)			(715	)
Gain on sale of customer service centers					—				(14,205	)			(619	)			(11,508	)			(26,332	)
Changes in working capital and other assets and liabilities					(15,677	)			(75,726	)			93,673				26,795				29,065
Net cash provided by (used in)
Operating activities				$	11,561			$	11,773			$	77,902			$	(8,171	)		$	93,065
Investing activities				$	(214,995	)		$	15,355			$	(4,464	)		$	7,547			$	(196,557	)
Financing activities				$	240,315			$	(18,348	)		$	(19,093	)		$	(61,666	)		$	141,208

39

---

ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A.	CONTROLS AND PROCEDURES

DISCLOSURE CONTROLS AND PROCEDURES.    The Partnership maintains disclosure controls and procedures (as defined in Rule 13a-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.

On December 1, 2005, before filing this Annual Report, the Partnership completed an evaluation under the supervision and with the participation of the Partnership’s management, including the Partnership’s principal executive officer and principal financial officer, of the effectiveness of the design and operation of the Partnership’s disclosure controls and procedures as of September 24, 2005. Based on this evaluation, the Partnership’s principal executive officer and principal financial officer concluded that the Partnership’s disclosure controls and procedures were effective at the reasonable assurance level as of September 24, 2005.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING.    Due to the deployment of various initiatives, including the implementation of new information technology systems during fiscal 2005, we modified many of our internal controls over financial reporting during the quarter ended September 24, 2005. This modification of internal control over financial reporting was made to align our internal controls with the implementation of our new technology initiatives, principally related to our natural gas and electricity segment. Management continues to monitor these changes, as well as conducting an ongoing process of reviewing and evaluating our internal control over financial reporting.

There have been no other changes in our internal control over financial reporting (as defined in Rule 13(a)–15(f) of the Securities Exchange Act of 1934) during the quarter ended September 24, 2005, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. Management’s Report on Internal Control over Financial Reporting is included below.

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING. Management of the Partnership is responsible for establishing and maintaining adequate internal control over financial reporting. The Partnership's internal control over financial reporting is designed to provide reasonable assurance as to the reliability of the Partnership's financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

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

The Partnership’s management has assessed the effectiveness of the Partnership’s internal control over financial reporting as of September 24, 2005. In making this assessment, the Partnership used the criteria established by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in ‘‘Internal Control-Integrated Framework.’’ These criteria are in the areas of control environment, risk assessment, control activities, information and communication, and monitoring. The Partnership's assessment included documenting, evaluating and testing of the design and operating effectiveness of its internal control over financial reporting.

Based on the Partnership’s assessment, as described above, management has concluded that, as of September 24, 2005, the Partnership’s internal control over financial reporting was effective.

40

---

Management’s assessment of the effectiveness of the Partnership's internal control over financial reporting as of September 24, 2005 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears in the ‘‘Report of Independent Registered Public Accounting Firm’’ on page F-2 of this Annual Report.

ITEM 9B.	OTHER INFORMATION

None.

41

---

PART III

ITEM 10.    DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The information to be included under the caption ‘‘Election of Supervisors’’ and ‘‘Information Concerning the Board and Board Committees’’ in the Partnership's definitive proxy statement to be filed with the SEC pursuant to Regulation 14A of the Exchange Act in connection with the 2006 tri-annual meeting of Common Unitholders of the Partnership (the ‘‘Proxy Statement’’) is incorporated herein by reference.

ITEM 11.    EXECUTIVE COMPENSATION

The information to be included under the caption ‘‘Executive Compensation’’ in the Proxy Statement is incorporated herein by reference.

ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The information to be included under the caption ‘‘Security Ownership of Certain Beneficial Owners and Management’’ in the Proxy Statement is incorporated herein by reference.

ITEM 13.    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The information to be included under the caption ‘‘Executive Compensation — Certain Relationships and Related Transactions’’ in the Proxy Statement is incorporated herein by reference.

ITEM 14.    PRINCIPAL ACCOUNTING FEES AND SERVICES

The information to be included under the caption ‘‘Principal Accounting Fees and Services’’ in the Proxy Statement is incorporated herein by reference.

42

---

PART IV

ITEM 15.    EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

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

	1.	Financial Statements

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

	2.	Financial Statement Schedule

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

	3.	Exhibits

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

43

---

SIGNATURES

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

				SUBURBAN PROPANE PARTNERS, L.P.
Date:   December 5, 2005				By:    /s/ MARK A. ALEXANDER                Mark A. Alexander            Chief Executive Officer and            Appointed Supervisor

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

Signature		Title		Date
/s/ MARK A. ALEXANDER		Chief Executive Officer and Appointed Supervisor		December 5, 2005
(MarkA. Alexander)
/s/ MICHAEL J. DUNN, JR.		President and Appointed Supervisor		December 5, 2005
(Michael J. Dunn, Jr.)
/S/ JOHN HOYT STOOKEY		Chairman and Elected Supervisor		December 5, 2005
(John Hoyt Stookey)
/s/ HAROLD R. LOGAN, JR.		Elected Supervisor		December 5, 2005
(Harold R. Logan, Jr.)
/s/ DUDLEY C. MECUM		Elected Supervisor		December 5, 2005
(Dudley C. Mecum)
/s/ ROBERT M. PLANTE		Vice President and Chief Financial Officer		December 5, 2005
(Robert M. Plante)
/s/ MICHAEL A. STIVALA		Controller and Chief Accounting Officer		December 5, 2005
(Michael A. Stivala)

44

---

INDEX TO EXHIBITS

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

Exhibit Number				Description
2.1				Recapitalization Agreement dated as of November 27, 1998 by and among the Partnership, the Operating Partnership, the General Partner, Millennium and Suburban Energy Services Group LLC. (Incorporated by reference to Exhibit 2.1 to the Partnership’s Current Report on Form 8-K filed December 3, 1998).
3.1				Second Amended and Restated Agreement of Limited Partnership of the Partnership dated as of May 26, 1999. (Incorporated by reference to the Partnership’s Proxy Statement filed pursuant to Section 14(a) of the Securities Exchange Act of 1934 on April 22, 1999).
3.2				Second Amended and Restated Agreement of Limited Partnership of the Operating Partnership dated as of May 26, 1999. (Incorporated by reference to the Partnership’s Proxy Statement filed pursuant to Section 14(a) of the Securities Exchange Act of 1934 on April 22, 1999).
4.1				Indenture, dated as of December 23, 2003, between Suburban Propane Partners, L.P., Suburban Energy Finance Corp. and The Bank of New York, as Trustee (including Form of Senior Global Exchange Note). (Incorporated by reference to Exhibit 10.28 to the Partnership’s Quarterly Report on Form 10-Q For the fiscal quarter ended December 27, 2003).
4.2				Exchange and Registration Rights Agreement, dated December 23, 2003 among Suburban Propane Partners, L.P., Suburban Energy Finance Corp., Wachovia Capital Markets, LLC and Goldman, Sachs & Co. (Incorporated by reference to Exhibit 4.1 to the Partnership’s registration statement on Form S-4 dated December 19, 2003).
4.3				Exchange and Registration Rights Agreement, dated March 31, 2005 among Suburban Propane Partners, L.P., Suburban Energy Finance Corp., Wachovia Capital Markets, LLC and Goldman, Sachs & Co. (Incorporated by reference to Exhibit 4.1 to the Partnership’s Current Report of Form 8-K filed April 1, 2005).
10.1				Employment Agreement dated as of March 5, 1996 between the Operating Partnership and Mr. Alexander. (Incorporated by reference to Exhibit 10.13 to the Partnership’s Current Report on Form 8-K filed April 29, 1996).
10.2				First Amendment to Employment Agreement dated as of March 5, 1996 between the Operating Partnership and Mr. Alexander entered into as of October 23, 1997. (Incorporated by reference to Exhibit 10.13 to the Partnership’s Current Report on Form 8-K filed April 29, 1996).
10.3				Second Amendment to Employment Agreement dated as of March 5, 1996 between the Operating Partnership and Mr. Alexander entered into as of April 14, 1999. (Incorporated by reference to Exhibit 10.15 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 27, 1997).
10.4				Form of Third Amendment to Employment Agreement dated as of March 5, 1996 between the Operating Partnership and Mr. Alexander, entered into November 2, 2005 (filed herewith).
10.5				Suburban Propane Partners, L.P. 2000 Restricted Unit Plan. (Incorporated by reference to Exhibit 10.16 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 30, 2000).

E-1

---

Exhibit Number				Description
10.6				The Partnership’s Severance Protection Plan dated September 1996. (Incorporated by reference to Exhibit 10.18 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 28, 1996).
10.7				Form of Amendment to Suburban Propane Severance Protection Plan for Key Employees, adopted November 2, 2005 (filed herewith).
10.8				Suburban Propane, L.P. Long Term Incentive Plan, as amended and restated effective October 1, 1999. (Incorporated by reference to Exhibit 10.19 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 28, 2002).
10.9				Form of Amendment to Suburban Propane, L.P. Long Term Incentive Program, adopted November 2, 2005 (filed herewith).
10.10				Suburban Propane L.P. 2003 Long Term Incentive Plan. (Incorporated by reference to Exhibit 10.7 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 25, 2004).
10.11				Benefits Protection Trust dated May 26, 1999 by and between Suburban Propane Partners, L.P. and First Union National Bank. (Incorporated by reference to the Partnership’s Quarterly Report on Form 10-Q for the fiscal quarter ended June 26, 1999).
10.12				Compensation Deferral Plan of Suburban Propane Partners, L.P. and Suburban Propane, L.P. amended and restated as of January 1, 2004. (Incorporated by reference to Exhibit 10. 9 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 25, 2004).
10.13				Form of Amendment to Compensation Deferral Plan of Suburban Propane Partners, L.P. and Suburban Propane, L.P., adopted November 2, 2005 (filed herewith).
10.14				Amended and Restated Supplemental Executive Retirement Plan of the Partnership (effective as of January 1, 1998). (Incorporated by reference to Exhibit 10.23 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 29, 2001).
10.15				Amended and Restated Retirement Savings and Investment Plan of Suburban Propane effective as of January 1, 1998). (Incorporated by reference to Exhibit 10.24 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 29, 2001).
10.16				Amendment No. 1 to the Retirement Savings and Investment Plan of Suburban Propane (effective January 1, 2002). (Incorporated by reference to Exhibit 10.25 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 28, 2002).
10.17				Third Amended and Restated Credit Agreement dated October 20, 2004, as amended by the First Amendment thereto dated March 17, 2005, as further amended by the Second Amendment thereto dated August 25, 2005. (Incorporated by reference to the Partnership’s Current Report on Form 8-K filed August 29, 2005).
10.18				First Amendment to the Third Amended and Restated Credit Agreement dated as of March 11, 2005 (Incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed April 1, 2005).

E-2

---

Exhibit Number				Description
10.19				Second Amendment to the Third Amended and Restated Credit Agreement dated as of August 26, 2005 (Incorporated by reference to the Partnership’s Current Report on Form 8-K filed August 29, 2005).
10.20				Asset Purchase Agreement by and Among Agway Energy Products, LLC, Agway Energy Services, Inc., Agway Energy Services PA, Inc., Agway, Inc. and Suburban Propane, L.P., dated as of November 10, 2003 (incorporated by reference to Exhibit 10.28 to the Partnership's Current Report on Form 8-K filed December 5, 2003).
14.1				Code of Ethics. (Incorporated by reference to Exhibit 14.1 to the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 25, 2004).
21.1				Subsidiaries of Suburban Propane Partners, L.P. (incorporated by reference to Exhibit 21.1 of the Partnership’s Annual Report on Form 10-K for the year ended September 25, 2004).
23.1				Consent of Independent Registered Public Accounting Firm. (Filed herewith).
31.1				Certification of the Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. (Filed herewith).
31.2				Certification of the Vice President and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. (Filed herewith).
32.1				Certification of the Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (Filed herewith).
32.2				Certification of the Vice President and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (Filed herewith).

E-3

---

INDEX TO FINANCIAL STATEMENTS

SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES

				Page
Report of Independent Registered Public Accounting Firm				F-2
Consolidated Balance Sheets – As of September 24, 2005 and September 25, 2004				F-4
Consolidated Statements of Operations – Years Ended September 24, 2005, September 25, 2004 and September 27, 2003				F-5
Consolidated Statements of Cash Flows – Years Ended September 24, 2005, September 25, 2004 and September 27, 2003				F-6
Consolidated Statements of Partners’ Capital – Years Ended September 24, 2005, September 25, 2004 and September 27, 2003				F-7
Notes to Consolidated Financial Statements				F-8

F-1

---

Report of Independent Registered Public Accounting Firm

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

We have completed an integrated audit of Suburban Propane Partners, L.P.’s 2005 consolidated financial statements and of its internal control over financial reporting as of September 24, 2005 and audits of its 2004 and 2003 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

Consolidated financial statements and financial statement schedule

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Suburban Propane Partners, L.P. and its subsidiaries at September 24, 2005 and September 25, 2004, and the results of their operations and their cash flows for each of the three years in the period ended September 24, 2005 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

Internal control over financial reporting

Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A, that Suburban Propane Partners, L.P. maintained effective internal control over financial reporting as of September 24, 2005 based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of September 24, 2005, based on criteria established in Internal Control – Integrated Framework issued by the COSO. The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Partnership’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to

F-2

---

permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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

/s/ PRICEWATERHOUSECOOPERS LLP
PricewaterhouseCoopers LLP
Florham Park, New Jersey
December 5, 2005

F-3

---

SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(in thousands)

				September 24, 2005				September 25, 2004
ASSETS
Current assets:
Cash and cash equivalents				$	14,411			$	53,481
Accounts receivable, less allowance for doubtful accounts of $9,965 and $7,896, respectively					109,918				91,000
Inventories					80,565				64,141
Prepaid expenses and other current assets					31,909				44,272
Total current assets					236,803				252,894
Property, plant and equipment, net					399,985				406,702
Goodwill					281,359				282,015
Other intangible assets, net					20,685				25,582
Other assets					26,765				24,814
Total assets				$	965,597			$	992,007
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Accounts payable				$	63,569			$	60,664
Accrued employment and benefit costs					20,291				25,152
Short-term borrowings					26,750				—
Current portion of long-term borrowings					475				42,940
Accrued insurance					11,505				12,724
Customer deposits and advances					62,099				61,265
Accrued interest					10,975				10,067
Other current liabilities					26,548				32,152
Total current liabilities					222,212				244,964
Long-term borrowings					548,070				472,975
Postretirement benefits obligation					31,058				31,616
Accrued insurance					34,952				25,517
Accrued pension liability					40,206				35,035
Other liabilities					12,983				13,782
Total liabilities					889,481				823,889
Commitments and contingencies
Partners' capital:
Common Unitholders (30,279 and 30,257 units issued and outstanding at September 24, 2005 and September 25, 2004, respectively)					159,199				238,880
General Partner					(1,779	)			852
Deferred compensation					(5,887	)			(5,778	)
Common Units held in trust, at cost					5,887				5,778
Unearned compensation					(4,355	)			(3,845	)
Accumulated other comprehensive loss					(76,949	)			(67,769	)
Total partners' capital					76,116				168,118
Total liabilities and partners' capital				$	965,597			$	992,007

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

F-4

---

SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES

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

				Year Ended
				September 24, 2005				September 25, 2004				September 27, 2003
Revenues
Propane				$	969,943			$	856,109			$	680,840
Fuel oil and refined fuels					431,223				281,682				—
Natural gas and electricity					102,803				68,452				—
HVAC					106,115				92,072				46,938
Other					10,150				8,939				7,297
					1,620,234				1,307,254				735,075
Costs and expenses
Cost of products sold					1,067,248				779,029				358,582
Operating					396,235				361,696				232,462
General and administrative					47,191				53,888				36,661
Restructuring costs (Note 7)					2,775				2,942				—
Impairment of goodwill (Note 6)					656				3,177				—
Depreciation and amortization					37,762				36,743				27,520
					1,551,867				1,237,475				655,225
Income before interest expense, loss on debt extinguishment and provision for income taxes					68,367				69,779				79,850
Loss on debt extinguishment					36,242				—				—
Interest income					(310	)			(429	)			(334	)
Interest expense					40,684				41,261				33,963
(Loss) income before provision for income taxes					(8,249	)			28,947				46,221
Provision for income taxes					803				3				202
(Loss) income from continuing operations					(9,052	)			28,944				46,019
Discontinued operations (Note 17):
Gain on sale of customer service centers					976				26,332				2,483
(Loss) income from discontinued service centers					—				(972	)			167
Net (loss) income				$	(8,076	)		$	54,304			$	48,669
General Partner's interest in net (loss) income				$	(251	)		$	1,310			$	1,193
Limited Partners' interest in net (loss) income				$	(7,825	)		$	52,994			$	47,476
(Loss) income per Common Unit – basic
(Loss) income from continuing operations				$	(0.29	)		$	0.96			$	1.77
Discontinued operations					0.03				0.83				0.10
Net (loss) income				$	(0.26	)		$	1.79			$	1.87
Weighted average number of Common Units outstanding – basic					30,276				29,599				25,359
(Loss) income per Common Unit – diluted
(Loss) income from continuing operations				$	(0.29	)		$	0.96			$	1.76
Discontinued operations					0.03				0.82				0.10
Net (loss) income				$	(0.26	)		$	1.78			$	1.86
Weighted average number of Common Units outstanding – diluted					30,276				29,705				25,495

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

F-5

---

SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)

				Year Ended
				September 24, 2005				September 25, 2004				September 27, 2003
Cash flows from operating activities:
Net (loss) income				$	(8,076	)		$	54,304			$	48,669
Adjustments to reconcile net income to net cash provided by operations:
Depreciation expense					32,865				33,344				27,097
Amortization of intangible assets					4,897				3,399				423
Amortization of debt origination costs					1,514				1,421				1,291
Amortization of unearned compensation					1,806				1,171				863
Amortization of discount on long-term borrowings					117				—				—
Gain on disposal of property, plant and equipment, net					(2,043	)			(715	)			(636	)
Gain on sale of customer service centers					(976	)			(26,332	)			(2,483	)
Pension settlement charge					—				5,337				—
Impairment of goodwill					656				3,177				—
Loss on debt extinguishment					36,242				—				—
Changes in assets and liabilities, net of businesses acquired and of dispositions:
(Increase)/decrease in accounts receivable					(18,918	)			10,047				(4,101	)
(Increase) in inventories					(16,424	)			(10,677	)			(5,339	)
Decrease/(increase) in prepaid expenses and other current assets					4,315				(13,155	)			576
Increase/(decrease) in accounts payable					3,326				17,603				(1,208	)
(Decrease)/increase in accrued employment and benefit costs					(4,861	)			1,024				(632	)
Increase/(decrease) in accrued interest					908				2,610				(1,209	)
(Decrease)/increase in other accrued liabilities					(5,989	)			20,233				(1,825	)
(Increase)/decrease in other noncurrent assets					(3,552	)			619				(7,435	)
Increase/(decrease) in other noncurrent liabilities					13,198				(10,345	)			3,249
Net cash provided by operating activities					39,005				93,065				57,300
Cash flows from investing activities:
Capital expenditures					(29,301	)			(26,527	)			(14,050	)
Acquisition of Agway Energy, net of cash acquired					—				(211,181	)			—
Proceeds from sale of property, plant and equipment					4,670				1,799				1,994
Proceeds from sale of customer service centers, net					—				39,352				7,197
Net cash used in investing activities					(24,631	)			(196,557	)			(4,859	)
Cash flows from financing activities:
Long-term debt repayments					(340,440	)			(42,911	)			(88,939	)
Long-term debt issuance, net of discount					372,953				175,000				—
Short-term borrowings					26,750				—				—
Expenses associated with debt agreements					(4,175	)			(5,947	)			(826	)
Prepayment premium associated with debt extinguishment					(31,980	)			—				—
Net proceeds from issuance of Common Units					—				87,566				72,186
Partnership distributions					(76,552	)			(72,500	)			(60,052	)
Net cash (used in)/provided by financing activities					(53,444	)			141,208				(77,631	)
Net (decrease)/increase in cash and cash equivalents					(39,070	)			37,716				(25,190	)
Cash and cash equivalents at beginning of year					53,481				15,765				40,955
Cash and cash equivalents at end of year					14,411				53,481				15,765
Supplemental disclosure of cash flow information:
Cash paid for interest				$	42,457			$	35,252			$	33,635
Non-cash adjustment for minimum pension liability				$	(1,242	)		$	2,096			$	(4,938	)

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

F-6

---

SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(in thousands)

				Number of Common Units				Common Unitholders				General Partner				Deferred Compensation				Common Units Held in Trust				Unearned Compensation				Accumulated Other Comprehensive (Loss)/Income				Total Partners' Capital				Comprehensive Income/(Loss)
Balance at September 28 , 2002					24,631			$	103,680			$	1,924			$	(11,567	)		$	11,567			$	(1,924	)		$	(84,394	)		$	19,286
Net income									47,476				1,193																				48,669			$	48,669
Other comprehensive income:
Net unrealized losses on cash flow hedges																													(1,129	)			(1,129	)			(1,129	)
Less: Reclassification of realized gains on cash flow hedges into earnings																													(683	)			(683	)			(683	)
Minimum pension liability adjustment																													4,938				4,938				4,938
Comprehensive income																																				$	51,795
Partnership distributions									(58,502	)			(1,550	)																			(60,052	)
Sale of Common Units under public offering, net of offering expenses					2,625				72,186																								72,186
Distribution of Common Units held in trust																	5,772				(5,772	)											—
Grants issued under Restricted
Unit Plan, net of forfeitures									1,110																(1,110	)							—
Amortization of Restricted
Unit Plan, net of forfeitures																									863								863
Balance at September 27 , 2003					27,256				165,950				1,567				(5,795	)			5,795				(2,171	)			(81,268	)			84,078
Net income									52,994				1,310																				54,304			$	54,304
Other comprehensive income:
Net unrealized gains on cash flow hedges																													9,129				9,129				9,129
Less: Reclassification of realized losses on cash flow hedges into earnings																													1,129				1,129				1,129
Non-cash pension settlement charge																													5,337				5,337				5,337
Minimum pension liability adjustment																													(2,096	)			(2,096	)			(2,096	)
Comprehensive income																																				$	67,803
Partnership distributions									(70,475	)			(2,025	)																			(72,500	)
Sale of Common Units under public offering, net of offering expenses					2,990				87,566																								87,566
Common Units issued under
Restricted Unit Plan					11
Common Units distributed into trust																	(159	)			159												—
Distribution of Common Units held in trust																	176				(176	)											—
Grants issued under Restricted Unit Plan, net of forfeitures									2,845																(2,845	)							—
Amortization of Restricted Unit Plan, net of forfeitures																									1,171								1,171
Balance at September 25, 2004					30,257				238,880				852				(5,778	)			5,778				(3,845	)			(67,769	)			168,118
Net loss									(7,825	)			(251	)																			(8,076	)		$	(8,076	)
Other comprehensive income/(loss):
Net unrealized losses on cash flow hedges																													(1,293	)			(1,293	)			(1,293	)
Less: Reclassification of realized gains on cash flow hedges into earnings																													(9,129	)			(9,129	)			(9,129	)
Minimum pension liability adjustment																													1,242				1,242				1,242
Comprehensive loss																																				$	(17,256	)
Partnership distributions									(74,172	)			(2,380	)																			(76,552	)
Common Units issued under
Restricted Unit Plan					22
Common Units distributed into trust																	(109	)			109												—
Grants issued under Restricted Unit Plan, net of forfeitures									2,316																(2,316	)							—
Amortization of Restricted Unit Plan, net of forfeitures																									1,806								1,806
Balance at September 24, 2005					30,279			$	159,199			$	(1,779	)		$	(5,887	)		$	5,887			$	(4,355	)		$	(76,949	)		$	76,116

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

F-7

---

SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES

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

1.	Partnership Organization and Formation

Suburban Propane Partners, L.P. (the ‘‘Partnership’’) is a publicly traded Delaware limited partnership principally engaged, through its operating partnership and subsidiaries, in the retail marketing and distribution of propane, fuel oil and other refined fuels, as well as the marketing of natural gas and electricity in deregulated markets. In addition, to complement its core marketing and distribution businesses, the Partnership installs and services a wide variety of home comfort equipment, particularly for heating, ventilation and air conditioning (‘‘HVAC’’). The limited partner interests in the Partnership are evidenced by common units traded on the New York Stock Exchange (‘‘Common Units’’), with 30,279,059 Common Units outstanding at September 24, 2005. The limited partners are entitled to participate in distributions and exercise the rights and privileges available to limited partners under the Second Amended and Restated Agreement of Limited Partners (the ‘‘Partnership Agreement’’), such as the election of three of the five members of the Board of Supervisors and vote on the removal of the general partner.

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

The general partner of both the Partnership and the Operating Partnership is Suburban Energy Services Group LLC (the ‘‘General Partner’’), a Delaware limited liability company. The General Partner is majority-owned by senior management of the Partnership and owns a combined 1.54% general partner interest in the Partnership and the Operating Partnership. The General Partner appoints two of the five members of the Board of Supervisors.

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

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

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

The Partnership serves more than 1,000,000 active residential, commercial, industrial and agricultural customers from approximately 370 customer service centers in 30 states. The Partnership’s operations are concentrated in the east and west coast regions of the United States. No single customer accounted for 10% or more of the Partnership’s revenues during fiscal 2005, 2004 or 2003. During fiscal 2005, 2004 and 2003, three suppliers provided approximately 33%, 36% and 42%, respectively, of the Partnership’s total domestic propane supply. The Partnership believes that, if supplies from any of these three suppliers were interrupted, it would be able to secure adequate propane supplies from other sources without a material disruption of its operations.

F-8

---

2.	Summary of Significant Accounting Policies

Principles of Consolidation. The consolidated financial statements include the accounts of the Partnership and all of its direct and indirect subsidiaries. All significant intercompany transactions and account balances have been eliminated. The Partnership consolidates the results of operations, financial condition and cash flows of the Operating Partnership as a result of the Partnership’s 98.9899% limited partner interest in the Operating Partnership and its ability to influence control over the major operating and financial decisions through the powers of the Board of Supervisors provided for in the Partnership Agreement.

Fiscal Period. The Partnership’s fiscal year ends on the last Saturday nearest to September 30.

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

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

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

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

Derivative Instruments and Hedging Activities. The Partnership enters into a combination of exchange-traded futures and option contracts, forward contracts and in certain instances, over-the-counter options (collectively, ‘‘derivative instruments’’) to manage the price risk associated with future purchases of the commodities used in its operations, principally propane and fuel oil, as well as to ensure supply during periods of high demand. All derivative instruments are reported on the balance sheet, within other current assets or other current liabilities, at their fair values pursuant to Statement of Financial Accounting Standards (‘‘SFAS’’) No. 133, ‘‘Accounting for Derivative Instruments and Hedging Activities,’’ as amended by SFAS Nos. 137, 138 and 149 (‘‘SFAS 133’’). On the date that futures, forward and option contracts are entered into, the Partnership makes a determination as to whether the derivative instrument qualifies for designation as a hedge. Changes in the fair value of derivative instruments are recorded each period in current period earnings or other comprehensive income (loss) (‘‘OCI’’), depending on whether a derivative instrument is designated as a hedge and, if so, the type of hedge. For derivative instruments designated as cash flow hedges, the Partnership formally assesses, both at the hedge contract’s inception and on an ongoing basis, whether the hedge contract is highly effective in offsetting changes in cash flows of hedged items. Changes in the fair value of derivative instruments designated as cash flow hedges are reported in OCI to the extent effective and reclassified into cost of products sold during the same period in which the hedged item affects earnings. The mark-to-market gains or losses on ineffective portions of cash flow hedges used to hedge future purchases are recognized in operating expenses immediately. Changes in the fair value of derivative instruments that are not designated as hedges are recorded in current period earnings within operating expenses and reclassified to cost of products sold once realized.

F-9

---

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

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

A portion of the Partnership’s long-term borrowings bear interest at a variable rate based upon either LIBOR or Wachovia National Bank's prime rate, plus an applicable margin depending on the level of the Partnership’s total leverage. Therefore, the Partnership is subject to interest rate risk on the variable component of the interest rate. The Partnership manages part of its variable interest rate risk by entering into interest rate swap agreements. On March 31, 2005, the Partnership entered into a $125,000 interest rate swap contract in conjunction with the new Term Loan facility under the Revolving Credit Agreement (see Note 9). The interest rate swap is being accounted for under SFAS 133 and the Partnership has designated the interest rate swap as a cash flow hedge. Changes in the fair value of the interest rate swap are recognized in OCI until the hedged item is recognized in earnings. At September 24, 2005, the fair value of the interest rate swap amounted to $1,293 and is included within other liabilities.

Long-Lived Assets. Long-lived assets include:

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

Buildings				40 Years
Building and land improvements				10-40 Years
Transportation equipment				4-30 Years
Storage facilities				7-40 Years
Equipment, primarily tanks and cylinders				3-40 Years
Computer software				3-7 Years

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

Goodwill. Goodwill represents the excess of the purchase price over the fair value of net assets acquired. Goodwill is subject to an impairment review at a reporting unit level, on an annual basis in August of each

F-10

---

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

Other Intangible Assets. Other intangible assets consist of non-compete agreements and acquired leasehold interests, customer lists and tradenames. Non-compete agreements are amortized under the straight-line method over the periods of the related agreements, ending periodically between fiscal years 2006 and 2010. Leasehold interests are amortized under the straight-line method over the shorter of the lease term or the useful life of the related assets, through fiscal 2025. Customer lists and tradenames are amortized under the straight-line method over the estimated period for which the assets are expected to contribute to the future cash flows of the reporting entities to which they relate, ending periodically between fiscal years 2006 and 2019.

Accrued Insurance. Accrued insurance represents the estimated costs of known and anticipated or unasserted claims under the Partnership’s general and product, workers’ compensation and automobile insurance policies. Accrued insurance provisions for unasserted claims arising from unreported incidents are based on an analysis of historical claims data. For each claim, the Partnership records a self-insurance provision up to the estimated amount of the probable claim utilizing actuarially determined loss development factors applied to actual claims data. The Partnership maintains insurance coverage wherein our net exposure for insured claims is limited to the insurance deductible, claims above which are paid by the Partnership’s insurance carriers. For the portion of the estimated self-insurance liability that exceeds insurance deductibles, the Partnership records an asset within other assets related to the amount of the liability expected to be covered by insurance. Claims are generally settled within 5 years of origination.

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

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

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

F-11

---

Unit-Based Compensation. The Partnership accounts for unit-based compensation in accordance with Accounting Principles Board Opinion No. 25, ‘‘Accounting for Stock Issued to Employees’’, and related interpretations. Upon award of restricted units under the Partnership’s 2000 Restricted Unit Plan, unearned compensation equivalent to the market price of the Restricted Units on the date of grant is established as a reduction of partners’ capital. The unearned compensation is amortized ratably to expense over the restricted periods. The Partnership follows the disclosure only provision of SFAS No. 123, ‘‘Accounting for Stock-Based Compensation’’ (‘‘SFAS 123’’). Pro forma net income and net income per Common Unit under the fair value method of accounting for Restricted Units under SFAS 123 would be the same as reported net income and net income per Common Unit.

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

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

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

Net Income Per Unit. Basic net income per Common Unit, for each of the periods presented, is computed by dividing net income, after deducting the General Partner’s approximate 3.1% interest, by the weighted average number of outstanding Common Units. Diluted net income per Common Unit is computed by dividing net income, after deducting the General Partner’s approximate 3.1% interest, by the weighted average number of outstanding Common Units and time vested Restricted Units granted under the 2000 Restricted Unit Plan. Diluted net loss per Common Unit for the year ended September 24, 2005 does not include 134,471 Restricted Units as their effect would be anti-dilutive. In computing diluted net income per Common Unit, weighted average units outstanding used to compute basic net income per Common Unit were increased by 105,711 units for the year ended September 25, 2004 to reflect the potential dilutive effect of the time vested Restricted Units outstanding using the treasury stock method. Net income is allocated to the Common Unitholders and the General Partner in accordance with their respective Partnership ownership interests, after giving effect to any priority income allocations for incentive distributions allocated to the General Partner.

Computations of earnings per Common Unit are performed in accordance with Emerging Issues Task Force (‘‘EITF’’) consensus 03-6 ‘‘Participating Securities and the Two-Class Method Under FAS 128’’ (‘‘EITF 03-6’’), when applicable. EITF 03-6 requires, among other things, the use of the two-class method of computing earnings per unit when participating securities exist. The two-class method is an earnings allocation formula that computes earnings per unit for Common Units and participating securities according to distributions declared and participation rights in undistributed earnings, as if all of the earnings were distributed to limited partners and the general partner (inclusive of the incentive distribution rights of the General Partner which are considered participating securities for purposes of the application of EITF 03-6). EITF 03-6 was adopted by the Partnership at the end of fiscal 2004. However, the requirements of EITF 03-6 do not apply to the computation of net income (loss) per Common Unit in periods in which a net loss is reported and therefore did not have any impact on annual net loss per Common Unit for the year ended September 24, 2005. In addition, the application of EITF 03-6 on the

F-12

---

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

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

Recently Issued Accounting Standards. In March 2005, the Financial Accounting Standards Board (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 beginning with 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.

In December 2004, the FASB issued a revised SFAS No. 123, ‘‘Share-Based Payment’’ (‘‘SFAS 123R’’). SFAS 123R is a revision of SFAS No. 123 ‘‘Accounting for Stock-Based Compensation’’ and supersedes APB Opinion No. 25 ‘‘Accounting for Stock Issued to Employees’’. SFAS 123R requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant date fair value of the award. SFAS 123R eliminates the alternative of using the APB Opinion No. 25 intrinsic value method of accounting that was provided for in SFAS No. 123 as originally issued and requires that the compensation cost relating to share-based payment transactions be recognized in the financial statements. SFAS 123R is effective beginning with the Partnership’s fiscal year ending September 30, 2006. The Partnership has historically recognized unearned compensation associated with awards of equity instruments ratably to expense over the vesting period (see Note 10). Accordingly, adoption of SFAS 123R is not expected to have an impact on the Partnership’s consolidated financial position, results of operation or cash flows.

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

3.	Acquisition of Agway Energy

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

The Agway Acquisition was financed with net proceeds of $87,566 from the issuance of 2,990,000 Common Units in December 2003 (see Note 16) and a portion of the net proceeds from the offering of unsecured 6.875% senior notes (see Note 9). The results of Agway Energy have been included in the Partnership’s consolidated financial statements from the date of the Agway Acquisition. The cost of the Agway Acquisition was allocated to the assets acquired and liabilities assumed according to estimated fair values as follows:

F-13

---

Net current assets				$	31,241
Property, plant and equipment					112,187
Intangible assets					28,046
Goodwill					41,956
Other assets, principally environmental escrow asset (see Note 14)					13,750
Deferred tax assets					21,519
Deferred tax asset valuation allowance					(21,519	)
Severance and other restructuring costs					(2,225	)
Environmental reserve (see Note 14)					(13,750	)
Total cost of Agway Acquisition				$	211,205

The following unaudited pro forma information presents the results of operations of the Partnership as if the Agway Acquisition had occurred at the beginning of the periods presented. The pro forma information, however, is not necessarily indicative of the results of operations assuming the Agway Acquisition had occurred at the beginning of the periods presented, nor is it necessarily indicative of future results.

				Year Ended
				September 25, 2004				September 27, 2003
As reported
Revenues				$	1,307,254			$	735,075
Income from continuing operations					28,944				46,019
Income from continuing operations per Common Unit – basic				$	0.96			$	1.77
Pro Forma
Revenues				$	1,475,579			$	1,424,552
Income from continuing operations					33,235				56,302
Income from continuing operations per Common Unit – basic				$	1.10			$	2.17

The as reported and pro forma income from continuing operations for the year ended September 25, 2004 above includes the restructuring charge of $2,942 as further described in Note 7 below, the $5,337 non-cash pension settlement charge described in Note 12 below and the $3,177 non-cash charge for the impairment of goodwill described in Note 6 below. These charges were not reflected in the pro forma results for the year ended September 27, 2003.

4.	Distributions of Available Cash

The Partnership makes distributions to its partners approximately 45 days after the end of each fiscal quarter of the Partnership in an aggregate amount equal to its Available Cash for such quarter. Available Cash, as defined in the 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 98.46% to the Common Unitholders and 1.54% to the General Partner, subject to the payment of incentive distributions to the General Partner to the extent the quarterly distributions exceed a target distribution of $0.55 per Common Unit.

As defined in the Partnership Agreement, the General Partner has certain Incentive Distribution Rights (‘‘IDRs’’) which represent an incentive for the General Partner to increase distributions to Common Unitholders in excess of the target quarterly distribution of $0.55 per Common Unit. With regard to the first $0.55 of quarterly distributions paid in any given quarter, 98.46% 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 the December 2003 public offering and 98.11% and 1.89%, respectively, prior to the June 2003 public offering described in Note 16). With regard to the balance of quarterly distributions in excess of the $0.55 per Common Unit target distribution, 85% of the Available Cash is distributed to the Common Unitholders and 15% is distributed to the General Partner.

F-14

---

The following summarizes the quarterly distributions per Common Unit declared and paid in respect of each of the quarters in the three fiscal years in the period ended September 24, 2005:

				September 24, 2005				September 25, 2004				September 27, 2003
First Quarter				$	0.6125			$	0.5875			$	0.5750
Second Quarter					0.6125				0.6000				0.5750
Third Quarter					0.6125				0.6125				0.5875
Fourth Quarter					0.6125				0.6125				0.5875

On October 19, 2005, the Board of Supervisors declared a quarterly distribution of $0.6125 per Common Unit in respect of the fourth quarter of fiscal 2005, which was paid on November 8, 2005 to holders of record on November 1, 2005. This quarterly distribution includes incentive distributions payable to the General Partner to the extent the quarterly distribution exceeds $0.55 per Common Unit.

5.	Selected Balance Sheet Information

Inventories consist of the following:

				September 24, 2005				September 25, 2004
Propane and refined fuels				$	66,383			$	50,286
Natural gas					3,267				2,003
Appliances and related parts					10,915				11,852
				$	80,565			$	64,141

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

Property, plant and equipment consist of the following:

				September 24, 2005				September 25, 2004
Land and improvements				$	31,698			$	30,811
Buildings and improvements					76,746				77,119
Transportation equipment					40,257				43,529
Storage facilities					81,333				82,665
Equipment, primarily tanks and cylinders					436,918				424,174
Computer software					27,083				21,224
Construction in progress					9,954				10,088
					703,989				689,610
Less: accumulated depreciation					304,004				282,908
					399,985				406,702

Depreciation expense for the years ended September 24, 2005, September 25, 2004 and September 27, 2003 amounted to $32,865, $33,344 and $27,097, respectively. Depreciation expense for the year ended September 24, 2005 included a non-cash charge of $425 related to an impairment of assets as a result of a realignment of the Partnership’s field operations in the fourth quarter of fiscal 2005 (see Note 7). Depreciation expense for the year ended September 25, 2004 included a non-cash charge of $1,000 related to a write-down of assets abandoned as a result of facility integration efforts in the Partnership’s northeast operations following the Agway Acquisition. As of September 24, 2005, the Partnership had approximately $5,099 of assets held for sale which were included in property, plant and equipment and are being actively marketed.

F-15

---

6.	Goodwill and Other Intangible Assets

Goodwill represents the excess of the purchase price over the fair value of net assets acquired. In accordance with SFAS No. 142, ‘‘Goodwill and Other Intangible Assets’’ (‘‘SFAS 142’’), goodwill is not amortized to expense. Rather, goodwill is subject to an impairment review at a reporting unit level, on an annual basis in August of each year, or when an event occurs or circumstances change that would indicate potential impairment. As a result of the estimated discounted cash flows in the annual impairment review, the Partnership recorded a non-cash charge of $656 for the impairment of goodwill associated with its HVAC segment for the year ended September 24, 2005. During fiscal 2004, as a result of continued losses in one of the Partnership’s reporting units acquired in fiscal 1999, the carrying value of goodwill was considered to be fully impaired when applying the discounted cash flow valuation analysis. Accordingly, the Partnership recorded a non-cash charge of $3,177 within the consolidated statement of operations related to goodwill impairment for the year ended September 25, 2004.

The changes in the carrying amount of goodwill for the year ended September 24, 2005 are as follows:

				Propane				Fuel Oil and Refined Fuels				Natural Gas and Electricity				HVAC				All Other				Total
Balance as of September 27, 2003				$	240,059			$	—			$	—			$	—			$	3,177			$	243,236
Acquired goodwill					22,500				10,900				7,900				656				—				41,956
Goodwill impairment charge recognized																					(3,177	)			(3,177	)
Balance as of September 25, 2004				$	262,559			$	10,900			$	7,900			$	656			$	—			$	282,015
Goodwill impairment charge recognized					—				—				—				(656	)			—				(656	)
Balance as of September 24, 2005				$	262,559			$	10,900			$	7,900			$	—			$	—			$	281,359

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

				September 24, 2005				September 25, 2004
Customer lists				$	19,866			$	19,866
Tradenames					2,531				3,513
Non-compete agreements					4,956				5,467
Other					1,967				1,967
					29,320				30,813
Less: accumulated amortization					8,635				5,231
				$	20,685			$	25,582

Aggregate amortization expense related to other intangible assets for the years ended September 24, 2005, September 25, 2004 and September 27, 2003 was $4,897, $3,399 and $423, respectively. Amortization expense for the year ended September 24, 2005 included a non-cash charge of $810 attributable to an impairment in the value of tradenames associated with the HVAC segment which were acquired in the Agway Acquisition. Aggregate amortization expense related to other intangible assets for each of the five succeeding fiscal years as of September 24, 2005 is as follows: 2006 – $2,587; 2007 – $2,036; 2008 – $1,999, 2009 – $1,995 and 2010-$1,965.

7.	Restructuring Costs

For the year ended September 24, 2005, the Partnership recorded a restructuring charge of $2,775 within the consolidated statements of operations related primarily to employee termination costs incurred as a result of actions taken during fiscal 2005. Specifically, during the fourth quarter of fiscal 2005 the Partnership approved and initiated a plan of reorganization to realign the field operations in an effort to streamline the operating footprint and leverage the system infrastructure to achieve additional operational efficiencies and reduce costs. As a result of this field realignment, the Partnership recorded a restructuring charge of $2,150 during the fourth quarter of fiscal 2005 associated with severance and other employee benefits for approximately 85 positions eliminated under the plan.

F-16

---

During fiscal 2004, in connection with the initial integration of certain management and back office functions of Agway Energy, the Partnership’s management approved and initiated plans to restructure the operations of both the Partnership and Agway Energy. Restructuring charges of $2,942 related to plans that had an impact on the assets, employees and operations of the Partnership were recorded in the statement of operations for fiscal 2004 when specific decisions were approved and costs associated with such activities were incurred. Severance and other restructuring or relocation costs associated with assets, employees and operations of Agway Energy in the amount of $2,225 were recorded as liabilities assumed in the purchase business combination and resulted in an increase to goodwill (see Note 3).

The components of remaining restructuring charges are as follows:

				Reserve at September 25, 2004				Charges Through September 24, 2005				Utilization Through September 24, 2005				Reserve at September 24, 2005
Charges expensed:
Severance and other employee costs				$	715			$	2,625			$	(1,669	)		$	1,671
Other exit costs					—				150				—				150
Total				$	715			$	2,775			$	(1,669	)		$	1,821
Charges recorded in purchase accounting:
Severance and other employee costs				$	139			$	—			$	(139	)		$	—
Relocation costs					235				—				(116	)			119
Other exit costs					1,000				—				(699	)			301
Total				$	1,374			$	—			$	(954	)		$	420

The $2,241 in restructuring and other exit costs as of September 24, 2005 is expected to be paid over the course of the next twelve months.

8.    Income Taxes

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

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

				September 24, 2005				September 25, 2004				September 27, 2003
Current
Federal				$	(6	)		$	(302	)		$	10
State and local					809				305				192
Deferred					—				—				—
				$	803			$	3			$	202

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

F-17

---

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

				September 24, 2005				September 25, 2004				September 27, 2003
Income tax provision at federal statutory tax rate				$	(2,546	)		$	19,006			$	17,105
Impact of Partnership income not subject to federal income taxes					(10,710	)			(27,477	)			(20,221	)
Permanent differences					(1,632	)			1,135				—
Change in valuation allowance					14,888				7,336				3,362
State income taxes					809				305				192
Other, net					(6	)			(302	)			(236	)
Provision for income taxes				$	803			$	3			$	202

The components of net deferred taxes and the related valuation allowance as of September 24, 2005 and September 25, 2004 using current enacted tax rates are as follows:

				September 24, 2005				September 25, 2004
Deferred tax assets:
Net operating loss carryforwards				$	45,524			$	30,409
Allowance for doubtful accounts					1,946				1,097
Inventory					531				860
Amortization of intangible assets					557				531
Depreciation					48				—
Derivative instruments					1,777				301
Severance and other exit costs					375				473
Other accruals					740				1,301
Total deferred tax assets					51,498				34,972
Deferred tax liabilities:
Depreciation					—				261
Total deferred tax liabilities					—				261
Net deferred tax assets					51,498				34,711
Valuation allowance					(51,498	)			(34,711	)
Net deferred tax assets				$	—			$	—

In order to fully realize the net deferred tax assets, the Corporate Entities will need to generate future taxable income. A valuation allowance is provided when it is more likely than not that some portion or all of the deferred tax assets will not be realized. Based upon the level of current taxable income and projections of future taxable income of the Corporate Entities over the periods which deferred tax assets are expected to be deductible, management believes that it is more likely than not that the Partnership will not realize the full benefit of its deferred tax assets as of September 24, 2005 and September 25, 2004. Of the total valuation allowance as of September 24, 2005, $21,519 was established through purchase accounting for the Agway Acquisition in December 2003. To the extent that a reversal of a portion of the valuation allowance is warranted in the future, the reversal will be recorded as a reduction of goodwill with no impact on the deferred tax provision.

As of September 24, 2005, the Partnership had tax loss carryforwards for federal income tax reporting purposes of approximately $124,639 which are available to offset future federal taxable income and expire between 2011 and 2025.

F-18

---

9.    Short-Term and Long-Term Borrowings

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

				September 24, 2005				September 25, 2004
Senior Notes, 6.875%, due December 15, 2013, net of unamortized discount of $1,930				$	423,070			$	175,000
Term Loan, 6.29% to 7.16%, due March 31, 2010					125,000				—
Senior Notes, 7.54%, redeemed March 31, 2005					—				297,500
Senior Notes, 7.37%, redeemed March 31, 2005					—				42,500
Note payable , 8%, due in annual installments through 2006					475				915
Short-term borrowings under Revolving Credit Agreement					26,750				—
					575,295				515,915
Less: current portion					27,225				42,940
				$	548,070			$	472,975

On March 31, 2005, the Partnership completed a refinancing (the ‘‘Refinancing’’) of all of the outstanding principal amount of the Operating Partnership’s 1996 Senior Notes and the 2002 Senior Notes (as defined below). Under the Refinancing, the Partnership issued $250,000 of additional notes under the indenture governing the 2003 Senior Notes (see below) and received proceeds of approximately $246,875, net of a $2,047 discount on sale and related underwriter fees. In addition, the Operating Partnership entered into an amendment to its Revolving Credit Agreement (see below) to provide, among other things, for a five-year $125,000 term loan facility (the ‘‘Term Loan’’). The total net proceeds of approximately $371,875 from the Refinancing, together with cash of approximately $7,335, were used to prepay $297,500 outstanding principal amount of 1996 Senior Notes and $42,500 outstanding principal amount of 2002 Senior Notes (collectively, the ‘‘Redeemed Notes’’), including a prepayment premium of approximately $31,980, interest accrued on the Redeemed Notes of approximately $6,391 from the last interest payment date through the date of redemption and related costs associated with the Refinancing.

The Redeemed Notes required an annual principal repayment of $42,500 through 2012. The Refinancing replaced the annual cash requirement for principal amortization with the $125,000 five-year Term Loan due 2010 and the $250,000 of senior notes due 2013 issued under the indenture governing the 2003 Senior Notes, significantly extending the Partnership’s debt maturities and eliminating refinancing risk associated with the amortization of the Redeemed Notes. The Refinancing is expected to reduce the Partnership’s annual interest expense for at least the next five years. The Partnership recorded a one-time charge of approximately $36,242 for the year ended September 24, 2005 as a result of the Refinancing to reflect the loss on debt extinguishment associated with the prepayment premium and the write-off of $4,262 of unamortized bond issuance costs associated with retirement of the Redeemed Notes.

On December 23, 2003, the Partnership and its subsidiary Suburban Energy Finance Corporation issued $175,000 aggregate principal amount of Senior Notes (the ‘‘2003 Senior Notes’’) with an annual interest rate of 6.875%. On March 31, 2005, in conjunction with the Refinancing, the Partnership and Suburban Energy Finance Corporation issued $250,000 additional senior notes under the indenture governing the 2003 Senior Notes through a debt offering under Rule 144A and Regulation S of the Securities Act of 1933. On September 23, 2005, pursuant to a registration rights agreement, the Partnership exchanged the $250,000 senior notes that were issued on March 31, 2005 in the Refinancing with $250,000 senior notes that were registered with the SEC. The Partnership’s obligations under the 2003 Senior Notes are unsecured and rank senior in right of payment to any future subordinated indebtedness and equally in right of payment with any future senior indebtedness. The 2003 Senior Notes are structurally subordinated to, which means they rank effectively behind, any senior debt and other liabilities of the Operating Partnership. The 2003 Senior Notes mature on December 15, 2013, and require semi-annual interest payments that began on June 15, 2004. The Partnership is permitted to redeem some or all of the 2003 Senior Notes any time on or after December 15, 2008, at redemption prices specified in the indenture governing the 2003 Senior Notes. In addition, in the event of a change of control of the Partnership, as defined in the indenture governing the 2003 Senior Notes, the Partnership must offer to repurchase the

F-19

---

notes at 101% of the principal amount repurchased, if the holders of the notes exercise the right of repurchase. The 2003 Senior Notes contain certain restrictions applicable to the Partnership and certain of its subsidiaries with respect to (i) the incurrence of additional indebtedness; and, (ii) liens, investments, guarantees, loans, advances, payments, mergers, consolidations, distributions, sales of assets and other transactions.

On March 5, 1996, pursuant to a senior note agreement, the Operating Partnership issued $425,000 of Senior Notes (the ‘‘1996 Senior Notes’’) with an annual interest rate of 7.54%. The 1996 Senior Notes were scheduled to mature June 30, 2011, required semi-annual interest payments and obligated the Operating Partnership to repay the principal on the 1996 Senior Notes in equal annual installments of $42,500 which started on July 1, 2002. The first annual principal payment was refinanced on July 1, 2002 and the second and third annual principal payments were made on July 1, 2003 and 2004. The remaining outstanding principal amount of the 1996 Senior Notes of $297,500 was redeemed in full on March 31, 2005. On July 1, 2002, the Operating Partnership received $42,500 from the issuance of 7.37% Senior Notes due June 30, 2012 (the ‘‘2002 Senior Notes’’) in order to refinance the first annual principal payment of $42,500 under the 1996 Senior Notes. The 2002 Senior Notes were redeemed in full on March 31, 2005.

On October 20, 2004, the Operating Partnership executed 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 the Term Loan due March 31, 2010. The Revolving Credit Agreement, as amended, was scheduled to expire on October 20, 2008 and in addition to the Term Loan provided available credit of $150,000 in the form of a $75,000 revolving working capital facility and a separate $75,000 letter of credit facility. On August 26, 2005, the Partnership completed the second amendment to the Revolving Credit Agreement which, among other things, extended the maturity date to March 31, 2010 to coincide with the maturity of the Term Loan, eliminated the stand-alone $75,000 letter of credit facility and combined that credit with the existing revolving working capital facility and increased the available revolving borrowing capacity by an additional $25,000, thereby raising the amount of the working capital facility to $175,000 (including the $75,000 from the former stand-alone letter of credit facility). The increased borrowing capacity will provide additional financial flexibility to support the Partnership’s growth strategies, particularly in the current high commodity price environment. All other terms and conditions under the Revolving Credit Agreement remained the same.

Borrowings under the Revolving Credit Agreement, including the Term Loan, bear interest at a rate based upon either LIBOR or Wachovia National Bank's prime rate, plus, in each case, the applicable margin or the Federal Funds rate plus 1/2 of 1%. An annual facility fee ranging from 0.375% to 0.50%, based upon certain financial tests, is payable quarterly whether or not borrowings occur. As of September 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 notional principal amount of $125,000, effectively fixing the LIBOR portion of the interest rate at 4.66%. In return, the issuing lender will pay to the Operating Partnership a floating rate, namely LIBOR, on the same notional principal amount. The applicable margin above LIBOR, as defined in the Revolving Credit Agreement, is not included in, and will be paid in addition to this fixed interest rate of 4.66%. The fair value of the interest rate swap amounted to $1,293 at September 24, 2005 and is included in other liabilities 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. As a result of the Refinancing, the Partnership eliminated the requirement to maintain a leverage ratio and an interest coverage ratio associated with the Redeemed Notes without

F-20

---

adding comparable financial covenants under the 2003 Senior Notes. 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 Partnership and the Operating Partnership were in compliance with all covenants and terms of the 2003 Senior Notes and the Revolving Credit Agreement as of September 24, 2005.

Debt origination costs representing the costs incurred in connection with the placement of, and the subsequent amendment to, the Partnership’s Senior Notes and Revolving Credit Agreement were capitalized within other assets and are being amortized on a straight-line basis over the term of the respective debt agreements. Other assets at September 24, 2005 and September 25, 2004 include debt origination costs with a net carrying amount of $8,848 and $10,506, respectively. Aggregate amortization expense related to deferred debt origination costs included within interest expense for the years ended September 24, 2005, September 25, 2004 and September 27, 2003 was $1,514, $1,421 and $1,291, respectively.

The aggregate amounts of long-term debt maturities subsequent to September 24, 2005 are as follows: 2006 – $27,225; 2007 – $0; 2008 – $0; 2009 – $0; and, thereafter-$548,070.

10.    Restricted Unit Plans

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 (487,804 Common Units valued at the initial public offering price of $20.50 per unit) to executives, managers and other employees of the Partnership. Restricted Units issued under the 2000 Restricted Unit Plan vest over time with 25% of the Common Units vesting at the end of each of the third and fourth anniversaries of the issuance date and the remaining 50% of the Common Units vesting at the end of the fifth anniversary of the issuance date. The 2000 Restricted Unit Plan participants are not eligible to receive quarterly distributions or vote their respective Restricted Units until vested. Restrictions also limit the sale or transfer of the units during the restricted periods. The value of the Restricted Unit is established by the market price of the Common Unit at the date of grant. Restricted Units are subject to forfeiture in certain circumstances as defined in the 2000 Restricted Unit Plan.

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

				Units				Weighted Average Grant Date Fair Value Per Unit
Outstanding September 28, 2002					111,986			$	24.19
Awarded					44,288				27.74
Forfeited					(5,726	)			(20.66	)
Outstanding September 27, 2003					150,548			$	25.37
Awarded					115,730				30.64
Forfeited					(27,560	)			(25.46	)
Issued					(10,605	)			(20.66	)
Outstanding September 25, 2004					228,113			$	28.25
Awarded					94,239				33.20
Forfeited					(26,282	)			(30.92	)
Issued					(22,292	)			(24.77	)
Outstanding September 24, 2005					273,778			$	29.17

During the years ended September 24, 2005, September 25, 2004 and September 27, 2003, the Partnership amortized $1,806, $1,171 and $863, respectively, of unearned compensation associated with the 2000 Restricted Unit Plan, net of forfeitures.

F-21

---

11.    Compensation Deferral Plan

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

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

In January 2003, in accordance with the terms of the Deferral Plan, 297,310 of the deferred units were distributed to the members of the General Partner and are freely traded. Certain members of management elected to further defer receipt of their deferred units (totaling 299,511 Common Units) until January 2008. During fiscal 2005, an additional 3,272 Common Units with a fair value of $109 were deposited into the Deferral Plan on behalf of individuals electing to defer receipt of Common Units vested under the 2000 Restricted Unit Plan. During fiscal 2004, 5,310 Common Units were deposited into the Deferral Plan and 7,490 Common Units were distributed out of the Deferral Plan, resulting in a net reduction of $17 in the deferred compensation liability and a corresponding reduction in the value of Common Units held in trust, both within partners’ capital.

As of September 24, 2005 and September 25, 2004, there were 300,603 and 297,331 Common Units, respectively, held in trust under the Deferral Plan. The value of the Common Units deposited in the trust and the related deferred compensation liability in the amount of $5,887 and $5,778 as of September 24, 2005 and September 25, 2004, respectively, are reflected in the accompanying consolidated balance sheets as components of partners’ capital. On November 2, 2005, the Deferral Plan was amended to, among other things, disallow any additional deferrals of Common Units into the trust subsequent to December 31, 2004.

12.    Employee Benefit Plans

Defined Contribution Plan. The Partnership has a defined contribution plan covering most employees. Employer contributions and costs are a percent of the participating employees’ compensation, subject to the achievement of annual performance targets of the Partnership. These contributions totaled $183, $1,261 and $1,305 for the years ended September 24, 2005, September 25, 2004 and September 27, 2003, respectively.

Pension Benefits and Retiree Health and Life Benefits.

Pension Benefits. The Partnership has a noncontributory defined benefit pension plan which was originally designed to cover all eligible employees of the Partnership who met certain requirements as to age and length of service. Effective January 1, 1998, the Partnership amended its noncontributory defined benefit pension plan to provide for a cash balance format as compared to a final average pay format which was in effect prior to January 1, 1998. The cash balance format is designed to evenly spread the growth of a participant’s earned retirement benefit throughout his/her career as compared to the final average pay format, under which a greater portion of employee benefits were earned toward the latter stages of one’s career. Effective January 1, 2000, participation in the noncontributory defined benefit pension plan was

F-22

---

limited to eligible participants in existence on that date with no new participants eligible to participate in the plan. On September 20, 2002, the Board of Supervisors approved an amendment to the defined benefit pension plan whereby, effective January 1, 2003, future service credits ceased and eligible employees will now receive interest credits only toward their ultimate retirement benefit.

Contributions, as needed, are made to a trust maintained by the Partnership. The trust’s assets consist primarily of domestic and international mutual funds, as well as fixed income securities. Contributions to the defined benefit pension plan are made by the Partnership in accordance with the Employee Retirement Income Security Act of 1974 minimum funding standards plus additional amounts which may be determined from time to time. There were no minimum funding requirements for the defined benefit pension plan for fiscal 2005, 2004 or 2003. Recently, there has been increased scrutiny over cash balance defined benefit pension plans and resulting litigation regarding such plans sponsored by other companies. These developments may result in legislative changes impacting cash balance defined benefit pension plans in the future. While no such legislative changes have been adopted, and if adopted the impact on the Partnership’s defined benefit pension plan is not certain, there can be no assurances that future legislative developments will not have an adverse effect on the Partnership’s results of operations or cash flows.

Retiree Health and Life Benefits. The Partnership provides postretirement health care and life insurance benefits for certain retired employees. Partnership employees hired prior to July 1993 and that retired prior to March 1998 are eligible for such benefits if they reached a specified retirement age while working for the Partnership. Effective January 1, 2000, the Partnership terminated its postretirement benefit plan for all eligible employees retiring after March 1, 1998. All active and eligible employees who were to receive benefits under the postretirement plan subsequent to March 1, 1998, were provided a settlement by increasing their accumulated benefits under the cash balance pension plan noted above. The Partnership’s postretirement health care and life insurance benefit plans are unfunded.

Projected Benefit Obligation, Fair Value of Plan Assets and Funded Status. The following tables provide a reconciliation of the changes in the benefit obligations and the fair value of the plan assets for each of the years ended September 24, 2005 and September 25, 2004 and a statement of the funded status for both years using an end of year measurement date:

				Pension Benefits								Retiree Health and Life Benefits
				2005				2004				2005				2004
Reconciliation of benefit obligations:
Benefit obligation at beginning of year				$	177,056			$	174,176			$	35,506			$	37,182
Service cost					—				—				18				18
Interest cost					9,107				9,765				1,783				2,138
Actuarial loss/(gain)					12,025				13,415				(1,377	)			(956	)
Settlement payments					(8,251	)			(12,288	)			—				—
Benefits paid					(7,858	)			(8,012	)			(2,257	)			(2,876	)
Benefit obligation at end of year				$	182,079			$	177,056			$	33,673			$	35,506
Reconciliation of fair value of plan assets:
Fair value of plan assets at beginning of year				$	142,021			$	132,040			$	—			$	—
Actual return on plan assets					15,961				15,181				—				—
Employer contributions					—				15,100				2,257				2,876
Settlement payments					(8,251	)			(12,288	)			—				—
Benefits paid					(7,858	)			(8,012	)			(2,257	)			(2,876	)
Fair value of plan assets at end of year				$	141,873			$	142,021			$	—			$	—

F-23

---

				Pension Benefits								Retiree Health and Life Benefits
				2005				2004				2005				2004
Reconciliation of benefit obligations:
Funded status:
Funded status at end of year				$	(40,206	)		$	(35,035	)		$	(33,673	)		$	(35,506	)
Unrecognized prior service cost					—				—				(865	)			(1,585	)
Net unrecognized actuarial losses					75,656				76,898				1,269				2,646
Net amount recognized at end of year				$	35,450			$	41,863			$	(33,269	)		$	(34,445	)
Amounts recognized in consolidated balance sheets consist of:
Prepaid benefit cost				$	—			$	—			$	—			$	—
Accrued benefit liability					(40,206	)			(35,035	)			(33,269	)			(34,445	)
Accumulated other comprehensive (loss)					75,656				76,898				—				—
Net amount recognized at end of year				$	35,450			$	41,863				(33,269	)			(34,445	)
Less: Current portion													2,211				2,829
Non-current benefit liability												$	(31,058	)		$	(31,616	)

The change in accumulated other comprehensive (loss) attributable to a favorable movement in the minimum pension liability for the year ended September 24, 2005 was $1,242. During fiscal 2004, lump sum benefit payments to either terminated or retired individuals amounted to $12,288. The lump sum benefit payments exceeded the interest cost component of the net periodic pension cost of $9,765 and, as a result, the Partnership was required to recognize a non-cash settlement charge of $5,337 during the fourth quarter of fiscal 2004, pursuant to SFAS 88 ‘‘Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits.’’ The non-cash charge was required to accelerate recognition of a portion of cumulative unrecognized losses in the defined benefit pension plan. These unrecognized losses were previously accumulated as a reduction to partners’ capital (cumulative reduction of $80,139 as of the end of the 2003 fiscal year) and were being amortized to expense as part of the Partnership’s net periodic pension cost in accordance with SFAS 87 ‘‘Employers’ Accounting for Pensions.’’

The Partnership made voluntary contributions of $15,100 and $10,000 to the defined benefit pension plan during fiscal 2004 and 2003, respectively, thereby taking proactive steps to improve the funded status of the plan and reduce the minimum pension liability.

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

				September 24, 2005 Actual Allocation				September 25, 2004 Actual Allocation
Common stock					42	%			42	%
Corporate bonds					0	%			8	%
Government bonds					0	%			12	%
Mutual funds					55	%			30	%
Cash and cash equiva lents					3	%			8	%
					100	%			100	%

The Partnership’s investment policies and strategies, as set forth in the Investment Management Policy and Guidelines, are monitored by a Benefits Committee comprised of seven members of management. The investment objective related to the defined benefit pension plan assets is to maximize total return with strong emphasis on the preservation of capital. The target asset mix is as follows: (i) the domestic equity portfolio should range between 40% and 60%; (ii) the international equity portfolio should range between 5% and 25%; and, (iii) the fixed income portion of the portfolio should range between 20% and 50%.

F-24

---

Projected Contributions and Benefit Payments. There are no projected minimum funding requirements under the Partnership’s defined benefit pension plan for fiscal 2006. The Partnership estimates that retiree health and life benefit contributions will be $2,959 for fiscal 2006. Estimated future benefit payments for both pension and retiree health and life benefits are as follows:

Fiscal Year				Pension Benefits				Retiree Health and Life Benefits
2006				$	17,940			$	2,959
2007					14,695				2,921
2008					14,725				2,868
2009					14,974				2,810
2010					14,838				2,734
2011 through 2015					68,985				12,950

Effect on Operations. The following table provides the components of net periodic pension costs included in operating expenses for the years ended September 24, 2005, September 25, 2004 and September 27, 2003:

				Pension Benefits												Retiree Health and Life Benefits
				2005				2004				2003				2005				2004				2003
Service cost				$	—			$	—			$	629			$	18			$	18			$	17
Interest cost					9,107				9,765				11,376				1,783				2,138				2,641
Expected return on plan assets					(9,335	)			(9,848	)			(12,161	)			—				—				—
Amortization of prior service cost					—				—				—				(720	)			(720	)			(720	)
Settlement charge					—				5,337				—				—				—				—
Recognized net actuarial loss					6,641				5,986				4,066				—				—				342
Net periodic benefit costs				$	6,413			$	11,240			$	3,910			$	1,081			$	1,436			$	2,280

Actuarial Assumptions. The assumptions used in the measurement of the Partnership’s benefit obligations as of September 24, 2005 and September 25, 2004 are shown in the following table:

				Pension Benefits								Retiree Health and Life Benefits
				2005				2004				2005				2004
Weighted-average discount rate					5.25	%			5.50	%			5.25	%			5.25	%
Average rate of compensation increase					n/a				n/a				n/a				n/a

The assumptions used in the measurement of periodic pension and postretirement benefit costs for the years ended September 24, 2005, September 25, 2004 and September 27, 2003 are shown in the following table:

				Pension Benefits												Retiree Health and Life Benefits
				2005				2004				2003				2005				2004				2003
Weighted-average discount rate					5.50	%			6.00	%			6.75	%			5.25	%			6.00	%			6.75	%
Average rate of compensation increase					n/a				n/a				n/a				n/a				n/a				n/a
Weighted-average expected long-term rate of return on plan assets					7.50	%			7.75	%			8.50	%			n/a				n/a				n/a
Health care cost trend					n/a				n/a				n/a				11.00	%			11.50	%			13.00	%

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

The 11.00% increase in health care costs assumed at September 24, 2005 is assumed to decrease gradually to 5.00% in fiscal 2013 and to remain at that level thereafter. Increasing the assumed health care cost trend rates by 1.0% in each year would increase the Partnership’s benefit obligation as of September 24, 2005

F-25

---

by approximately $967 and the aggregate of service and interest components of net periodic postretirement benefit expense for the year ended September 24, 2005 by approximately $60. Decreasing the assumed health care cost trend rates by 1.0% in each year would decrease the Partnership’s benefit obligation as of September 24, 2005 by approximately $855 and the aggregate of service and interest components of net periodic postretirement benefit expense for the year ended September 24, 2005 by approximately $54. The Partnership has concluded that the prescription drug benefits within the retiree medical plan will not qualify for a Medicare subsidy available under recent legislation.

13.    Financial Instruments

Derivative Instruments and Hedging Activities. The Partnership purchases propane and refined fuels at various prices that are eventually sold to its customers, exposing the Partnership to market fluctuations in the price of these commodities. A control environment has been established which includes policies and procedures for risk assessment and the approval, reporting and monitoring of derivative instruments and hedging activities. The Partnership closely monitors the potential impacts of commodity price changes and, where appropriate, utilizes commodity futures, forward and option contracts to hedge its commodity price risk, to protect margins and to ensure supply during periods of high demand. Derivative instruments are used to hedge a portion of the Partnership’s forecasted purchases for no more than one year in the future. There were no unrealized gains or losses associated with the Partnership’s commodity price hedging activities included in OCI as of September 24, 2005.

For the years ended September 24, 2005, September 25, 2004 and September 27, 2003, operating expenses included unrealized losses in the amount of $2,497, $4,523 and $1,500, respectively, attributable to changes in the fair value of derivative instruments not designated as hedges. In connection with the Agway Acquisition, the Partnership acquired certain futures and option contracts that were identified as hedges of future purchases of fuel oil and propane with a fair value of $6,327 which were recorded as derivative assets at fair value in purchase accounting. As the underlying futures and option contracts were settled during fiscal 2004, the derivative assets were charged to cost of products sold as an offset to the realized gains from contract settlement. The impact on cost of products sold represented a non-cash charge resulting from the application of purchase accounting on derivative instruments acquired. For the year ended September 25, 2004, the Partnership recorded a non-cash charge of $6,327 within cost of products sold related to contracts settled during the period.

In addition, borrowings under the Term Loan bear interest at a variable rate based upon either LIBOR or Wachovia National Bank's prime rate, plus an applicable margin depending on the level of the Operating Partnership’s total leverage. Therefore, the Partnership is subject to interest rate risk on the variable component of the interest rate. On March 31, 2005, the Partnership entered into an interest rate swap agreement in order to manage its interest rate risk. The interest rate swap is being accounted for under SFAS 133 and has been designated as a cash flow hedge. Changes in the fair value of the interest rate swap are recognized in OCI until the hedged item is recognized in earnings. As of September 24, 2005, an unrealized loss of $1,293 was included in OCI attributable to the interest rate swap agreement and is expected to be recognized in earnings as the interest on the Term Loan impacts earnings through March 31, 2010. However, due to changes in the interest rate environment, the corresponding value in OCI is subject to change prior to its impact on earnings.

Credit Risk. The Partnership’s principal customers are residential and commercial end users of propane and refined fuels served by approximately 370 customer service centers in 30 states. No single customer accounted for more than 10% of revenues during fiscal 2005, 2004 or 2003 and no concentration of receivables exists at the end of fiscal 2005 or 2004.

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

F-26

---

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

14.    Commitments and Contingencies

Commitments. The Partnership leases certain property, plant and equipment, including portions of the Partnership’s vehicle fleet, for various periods under noncancelable leases. Rental expense under operating leases was $28,559, $27,315 and $24,337 for the years ended September 24, 2005, September 25, 2004 and September 27, 2003, respectively.

Future minimum rental commitments under noncancelable operating lease agreements as of September 24, 2005 are as follows:

Fiscal Year

2006				$20,295
2007				15,096
2008				10,688
2009				5,856
2010 and thereafter				5,814

Contingencies. As discussed in Note 2, the Partnership is self-insured for general and product, workers’ compensation and automobile liabilities up to predetermined amounts above which third party insurance applies. At September 24, 2005 and September 25, 2004, the Partnership had accrued insurance liabilities of $46,457 and $38,241, respectively, representing the total estimated losses under these self-insurance programs. The Partnership is also involved in various legal actions which have arisen in the normal course of business, including those relating to commercial transactions and product liability. Management believes, based on the advice of legal counsel, that the ultimate resolution of these matters will not have a material adverse effect on the Partnership’s financial position or future results of operations, after considering its self-insurance liability for known and unasserted self-insurance claims. For the portion of the estimated self-insurance liability that exceeds insurance deductibles, the Partnership records an asset within other assets related to the amount of the liability expected to be covered by insurance which amounted to $10,046 and $2,941 as of September 24, 2005 and September 25, 2004, respectively.

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

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

With the Agway Acquisition, the Partnership acquired certain properties and assets, including fuel oil tanks and gasoline stations, that are subject to extensive federal, state and local environmental laws and

F-27

---

regulation, including investigation and remediation of contaminated soil and groundwater, transportation of hazardous materials, other environmental protection measures and health and safety matters. Based on a review of certain Phase I Environmental Site Assessments and, at certain sites, groundwater and/or soil sample analysis, the Partnership identified that certain of these properties had either known or probable environmental exposure, some of which are currently in varying stages of investigation, remediation or monitoring. Under the agreement for the Agway Acquisition, the seller was required to deposit $15,000 from the total purchase price into an escrow account to be used to fund remediation costs at the acquired properties. The escrowed funds will be used to fund environmental costs and expenses during the first three years following the closing date of the Agway Acquisition. Subject to amounts withheld with respect to any pending claims made prior to the third anniversary of the closing date of the Agway Acquisition, any remaining escrowed funds will be remitted to the seller at the end of the three-year period.

Based on the Partnership’s best estimate of future costs for environmental investigations, remediation and ongoing monitoring activities associated with acquired properties with either known or probable environmental exposures an environmental reserve in the amount of $13,750 was established in purchase accounting. The Partnership established a corresponding environmental escrow asset in the amount of $13,750 related to the future reimbursement from escrowed funds for environmental spending. As of September 24, 2005 and September 25, 2004, the environmental reserve amounted to $5,768 and $11,500, respectively, and the corresponding environmental escrow asset amounted to $6,151 and $11,500, respectively. The environmental reserves are recorded on an undiscounted basis.

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

Future developments, such as stricter environmental, health or safety laws and regulations thereunder, could affect Partnership operations. The Partnership anticipates that compliance with or liabilities under environmental, health and safety laws and regulations, including CERCLA, will not have a material adverse effect on the Partnership. To the extent that there are any environmental liabilities unknown to the Partnership or environmental, health or safety laws or regulations are made more stringent, there can be no assurance that the Partnership’s results of operations will not be materially and adversely affected.

15.    Guarantees

The Partnership has residual value guarantees associated with certain of its operating leases, related primarily to transportation equipment, with remaining lease periods scheduled to expire periodically through fiscal 2012. Upon completion of the lease period, the Partnership guarantees that the fair value of the equipment will equal or exceed the guaranteed amount, or the Partnership will pay the lessor the difference. Although the fair value of equipment at the end of its lease term has historically exceeded the guaranteed amounts, the maximum potential amount of aggregate future payments the Partnership could be required to make under these leasing arrangements, assuming the equipment is deemed worthless at the end of the lease term, is approximately $18,121. Of this amount, the fair value of residual value guarantees for operating leases entered into after December 31, 2002 was $6,292 and $3,684 as of September 24, 2005 and September 25, 2004, respectively, which is reflected in other liabilities, with a corresponding amount included within other assets, in the accompanying consolidated balance sheets.

16.    Public Offerings

On December 16, 2003, the Partnership sold 2,600,000 Common Units in a public offering at a price of $30.90 per Common Unit realizing proceeds of $76,026, net of underwriting commissions and other offering expenses. On December 23, 2003, following the underwriters’ full exercise of their over-allotment option, the Partnership sold an additional 390,000 Common Units at $30.90 per Common Unit, generating

F-28

---

additional net proceeds of $11,540. The aggregate net proceeds of $87,566 were used to fund a portion of the purchase price for the Agway Acquisition. These transactions increased the total number of Common Units outstanding to 30,256,767. As a result of the Public Offering, the combined General Partner interest in the Partnership was reduced from 1.71% to 1.54% while the Common Unitholder interest in the Partnership increased from 98.29% to 98.46%.

On June 18, 2003, the Partnership sold 2,282,500 Common Units in a public offering at a price of $29.00 per Common Unit realizing proceeds of $62,879, net of underwriting commissions and other offering expenses. On June 26, 2003, following the underwriters’ full exercise of their over-allotment option, the Partnership sold an additional 342,375 Common Units at $29.00 per Common Unit, generating additional net proceeds of $9,307. The aggregate net proceeds of $72,186 were used for general partnership purposes, including working capital and the repayment of outstanding borrowings under the Revolving Credit Agreement and the second annual principal payment of $42,500 due under the 1996 Senior Note Agreement on June 30, 2003. These transactions increased the total number of Common Units outstanding to 27,256,162. As a result of the Public Offering, the combined General Partner interest in the Partnership was reduced from 1.89% to 1.71% while the Common Unitholder interest in the Partnership increased from 98.11% to 98.29%.

17.    Discontinued Operations and Disposition

The Partnership continuously evaluates its existing operations to identify opportunities to optimize the return on assets employed and selectively divests operations in slower growing or non-strategic markets and seeks to reinvest in markets that are considered to present more opportunities for growth. In line with that strategy, during fiscal 2004, the Partnership sold 24 customer service centers for net cash proceeds of $39,352. The Partnership recorded a gain on sale of $26,332 during fiscal 2004 which was accounted for within discontinued operations in accordance with SFAS No. 144, ‘‘Accounting for the Impairment or Disposal of Long-Lived Assets’’ (‘‘SFAS 144’’). During fiscal 2005, the Partnership finalized certain purchase price adjustments with the buyer of these customer service centers and recorded an additional gain on sale of $976. The individual captions on the consolidated statements of operations for the years ended September 25, 2004 and September 27, 2003 exclude the results from these discontinued operations, which were part of the Partnership’s propane segment.

During fiscal 2003, the Partnership sold nine customer service centers, which were part of the Partnership’s propane segment, for net cash proceeds of approximately $7,197. The Partnership recorded a gain on sale of $2,483 during fiscal 2003 which was accounted for within discontinued operations pursuant to SFAS 144.

18.    Segment Information

The Partnership manages and evaluates its operations in five reportable segments: Propane, Fuel Oil and Refined Fuels, Natural Gas and Electricity, HVAC and All Other. The chief operating decision maker evaluates performance of the operating segments using a number of performance measures, including gross margins and operating profit. Costs excluded from these profit measures are captured in Corporate and include corporate overhead expenses not allocated to the operating segments. Unallocated corporate overhead expenses include all costs of back office support functions that are reported as general and administrative expenses 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 in Note 2.

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

F-29

---

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.

The All other business segment is comprised of the activities from our HomeTown Hearth & Grill and Suburban Franchising subsidiaries.

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

F-30

---

				Year Ended
				September 24, 2005				September 25, 2004				September 27, 2003
Revenues:
Propane				$	969,943			$	856,109			$	680,840
Fuel oil and refined fuels					431,223				281,682				—
Natural gas and electricity					102,803				68,452				—
HVAC					106,115				92,072				46,938
All other					10,150				8,939				7,297
Total revenues				$	1,620,234			$	1,307,254			$	735,075
Income (loss) before interest expense, loss on debt extinguishment and provision for income taxes:
Propane				$	147,468			$	143,933			$	133,278
Fuel oil and refined fuels					(6,474	)			14,911				—
Natural gas and electricity					6,463				4,154				—
HVAC					(12,423	)			(2,686	)			(4,281	)
All other					(3,802	)			(8,125	)			(3,460	)
Corporate					(62,865	)			(82,408	)			(45,687	)
Total income before interest expense, loss on debt extinguishment and provision for income taxes					68,367				69,779				79,850
Reconciliation to income from continuing operations
Interest expense, net					40,374				40,832				33,629
Loss on debt extinguishment					36,242				—				—
Provision for income taxes					803				3				202
(Loss) income from continuing operations				$	(9,052	)		$	28,944			$	46,019
Depreciation and amortization:
Propane				$	25,393			$	26,347			$	22,908
Fuel oil and refined fuels					4,802				4,302				—
Natural gas and electricity					967				555				—
HVAC					1,509				640				80
All other					281				343				383
Corporate					4,810				4,556				4,149
Total depreciation and amortization				$	37,762			$	36,743			$	27,520

				As of
				September 24, 2005				September 25, 2004
Assets
Propane				$	735,094			$	720,645
Fuel oil and refined fuels					124,232				121,386
Natural gas and electricity					30,294				26,630
HVAC					15,590				20,715
All other					4,990				4,941
Corporate					143,378				185,671
Eliminations					(87,981	)			(87,981	)
Total assets				$	965,597			$	992,007

Income (loss) before interest expense, loss on debt extinguishment and provision for income taxes for the HVAC segment for the year ended September 24, 2005 included the non-cash charge of $656 for goodwill impairment (see Note 6). In addition, depreciation and amortization expense for the HVAC segment for the year ended September 24, 2005 reflects the non-cash charge of $810 for the impairment of other

F-31

---

intangible assets (see Note 6). Income (loss) before interest expense, loss on debt extinguishment and income taxes for the All other segment for the year ended September 25, 2004 included the $3,177 non-cash charge for goodwill impairment.

F-32

---

INDEX TO FINANCIAL STATEMENT SCHEDULE

SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES

								Page
Schedule II				Valuation and Qualifying Accounts – Years Ended September 24, 2005, September 25, 2004 and September 27, 2003					S-2

S-1

---

SCHEDULE II

SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES

VALUATION AND QUALIFYING ACCOUNTS
(in thousands)

				Balance at Beginning of Period				Charged to Costs and Expenses				Other Additions				Deductions				Balance at End of Period
Year Ended September 27, 2003
Allowance for doubtful accounts				$	1,894			$	3,315			$	—			$	(2,690	)		$	2,519
Year Ended September 25, 2004 (a)
Allowance for doubtful accounts				$	2,519			$	9,128			$	2,966			$	(6,717	)		$	7,896
Year Ended September 24, 2005
Allowance for doubtful accounts				$	7,896			$	9,289			$	—			$	(7,220	)		$	9,965

(a)	Other additions for the year ended September 25, 2004 reflects allowances for doubtful accounts associated with the acquisition of Agway Energy. Additionally, the increase in charges and deductions during fiscal 2004 was primarily attributable to the impact of increased sales and related accounts receivable from the Agway Energy operations.

S-2

---