Edgar Filing: SUBURBAN PROPANE PARTNERS LP

Form 10-Q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


þ		Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended June 27, 2009


o		Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Commission File Number: 1-14222

SUBURBAN PROPANE PARTNERS, L.P.

(Exact name of registrant as specified in its charter)


Delaware (State or other jurisdiction of incorporation or organization)		22-3410353 (I.R.S. Employer Identification No.)

240 Route 10 West
Whippany, NJ 07981
(973) 887-5300
(Address, including zip code, and telephone number,
including area code, of registrant’s principal executive offices)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). * Yes o No o


*		The registrant has not yet been phased into the interactive data requirements.

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
		(do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES

INDEX TO FORM 10-Q


	Page
PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS (UNAUDITED)

Condensed Consolidated Balance Sheets as of June 27, 2009 and September 27, 2008		1

Condensed Consolidated Statements of Operations for the three months ended June 27, 2009 and June 28, 2008		2

Condensed Consolidated Statements of Operations for the nine months ended June 27, 2009 and June 28, 2008		3

Condensed Consolidated Statements of Cash Flows for the nine months ended June 27, 2009 and June 28, 2008		4

Condensed Consolidated Statement of Partners’ Capital for the nine months ended June 27, 2009		5

Notes to Condensed Consolidated Financial Statements		6

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		20

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		36

ITEM 4. CONTROLS AND PROCEDURES		39

PART II. OTHER INFORMATION

ITEM 1A. RISK FACTORS		40

ITEM 6. EXHIBITS		41

SIGNATURES		42

Exhibit 3.2
Exhibit 3.3
Exhibit 10.1
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains forward-looking statements (“Forward-Looking Statements”) as defined in the Private Securities Litigation Reform Act of 1995 and Section 27A of the Securities Act of 1933, as amended, relating to future business expectations and predictions and financial condition and results of operations of Suburban Propane Partners, L.P. (the “Partnership”). Some of these statements can be identified by the use of forward-looking terminology such as “prospects,” “outlook,” “believes,” “estimates,” “intends,” “may,” “will,” “should,” “anticipates,” “expects” or “plans” or the negative or other variation of these or similar words, or by discussion of trends and conditions, strategies or risks and uncertainties. These Forward-Looking Statements involve certain risks and uncertainties that could cause actual results to differ materially from those discussed or implied in such Forward-Looking Statements (statements contained in this Quarterly Report identifying such risks and uncertainties are referred to as “Cautionary Statements”). The risks and uncertainties and their impact on the Partnership’s results include, but are not limited to, the following risks:

•

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

•

Volatility in the unit cost of propane, fuel oil and other refined fuels and natural gas, the impact of the Partnership’s hedging and risk management activities, and the adverse impact of price increases on volumes as a result of customer conservation;

•

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

•

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

•

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

•

The ability of the Partnership to retain customers;

•

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

•

The ability of management to continue to control expenses;

•

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

•

The impact of legal proceedings on the Partnership’s business;

•

The impact of operating hazards that could adversely affect the Partnership’s operating results to the extent not covered by insurance;

•

The Partnership’s ability to make strategic acquisitions and successfully integrate them; and

•

The impact of current conditions in the global capital and credit markets, and general economic pressures.

Some of these Forward-Looking Statements are discussed in more detail in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this Quarterly Report. Reference is also made to the risk factors discussed in Item 1A of our Annual Report on Form 10-K for the fiscal year ended September 27, 2008. On different occasions, the Partnership or its representatives have made or may make Forward-Looking Statements in other filings with the Securities and Exchange Commission (“SEC”), press releases or oral statements made by or with the approval of one of the Partnership’s authorized executive officers. Readers are cautioned not to place undue reliance on Forward-Looking Statements, which reflect management’s view only as of the date made. The Partnership undertakes no obligation to update any Forward-Looking Statement or Cautionary Statement except as otherwise required by law. All subsequent written and oral Forward-Looking Statements attributable to the Partnership or persons acting on its behalf are expressly qualified in their entirety by the Cautionary Statements in this Quarterly Report and in future SEC reports.

SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)

(unaudited)


	June 27,			September 27,
	2009			2008

ASSETS
Current assets:
Cash and cash equivalents	$	256,099		$	137,698
Accounts receivable, less allowance for doubtful accounts of $5,891 and $6,578, respectively		60,948			94,933
Inventories		57,734			79,822
Other current assets		25,705			47,098

Total current assets		400,486			359,551
Property, plant and equipment, net		358,247			367,808
Goodwill		274,902			276,282
Other intangible assets, net		14,353			16,018
Other assets		27,317			16,054

Total assets	$	1,075,305		$	1,035,713


LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	31,547		$	58,079
Accrued employment and benefit costs		36,556			27,053
Accrued insurance		10,530			41,120
Customer deposits and advances		48,359			71,206
Accrued interest		2,465			11,030
Other current liabilities		17,069			15,127

Total current liabilities		146,526			223,615
Long-term borrowings		523,947			531,772
Postretirement benefits obligation		16,868			17,153
Accrued insurance		42,214			31,913
Other liabilities		12,685			11,184

Total liabilities		742,240			815,637


Commitments and contingencies

Partners’ capital:
Common Unitholders (32,797 and 32,725 units issued and outstanding at June 27, 2009 and September 27, 2008, respectively)		374,552			264,231
Accumulated other comprehensive loss		(41,487	)		(44,155	)

Total partners’ capital		333,065			220,076

Total liabilities and partners’ capital	$	1,075,305		$	1,035,713

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

SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit amounts)

(unaudited)


	Three Months Ended
	June 27,			June 28,
	2009			2008
Revenues
Propane	$	139,571		$	216,999
Fuel oil and refined fuels		23,091			55,262
Natural gas and electricity		12,147			22,507
Services		8,321			9,184
All other		1,242			1,524

		184,372			305,476

Costs and expenses
Cost of products sold		87,463			212,974
Operating		72,295			76,455
General and administrative		13,108			13,268
Depreciation and amortization		7,713			7,159

		180,579			309,856

Income (loss) before interest expense and provision for (benefit from) income taxes		3,793			(4,380	)
Interest expense, net		10,068			9,524


Loss before provision for (benefit from) taxes		(6,275	)		(13,904	)
Provision for (benefit from) income taxes		1,160			(157	)


Net loss	$	(7,435	)	$	(13,747	)


Loss per Common Unit — basic	$	(0.23	)	$	(0.42	)

Weighted average number of Common Units outstanding — basic		32,859			32,725


Loss per Common Unit — diluted	$	(0.23	)	$	(0.42	)

Weighted average number of Common Units outstanding — diluted		32,859			32,725

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

SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit amounts)

(unaudited)


	Nine Months Ended
	June 27,		June 28,
	2009		2008
Revenues
Propane	$	750,392	$	946,700
Fuel oil and refined fuels		142,420		247,609
Natural gas and electricity		66,521		84,693
Services		30,574		34,752
All other		3,005		3,928

		992,912		1,317,682

Costs and expenses
Cost of products sold		469,952		871,446
Operating		236,206		235,495
General and administrative		45,671		37,632
Depreciation and amortization		21,867		21,325

		773,696		1,165,898

Income before interest expense and provision for income taxes		219,216		151,784
Interest expense, net		28,913		27,330


Income before provision for taxes		190,303		124,454
Provision for income taxes		2,184		1,956


Income from continuing operations		188,119		122,498
Discontinued operations:
Gain on sale of discontinued operations		—		43,707


Net income	$	188,119	$	166,205


Income per Common Unit — basic
Income from continuing operations	$	5.73	$	3.74
Discontinued operations		—		1.34

Net income	$	5.73	$	5.08

Weighted average number of Common Units outstanding — basic		32,849		32,719


Income per Common Unit — diluted
Income from continuing operations	$	5.70	$	3.72
Discontinued operations		—		1.33

Net income	$	5.70	$	5.05

Weighted average number of Common Units outstanding — diluted		33,026		32,941

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

SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(unaudited)


	Nine Months Ended
	June 27,			June 28,
	2009			2008
Cash flows from operating activities:
Net income	$	188,119		$	166,205
Adjustments to reconcile net income to net cash provided by operations:
Depreciation and amortization		21,867			21,325
Amortization of debt origination costs		1,410			996
Compensation cost recognized under Restricted Unit Plan		1,885			1,503
Amortization of discount on long-term borrowings		175			175
Gain on disposal of discontinued operations		—			(43,707	)
Gain on disposal of property, plant and equipment, net		(770	)		(1,821	)
Deferred tax provision		1,380			1,277
Changes in assets and liabilities:
Decrease (increase) in accounts receivable		33,985			(28,375	)
Decrease in inventories		22,088			2,541
Decrease in other current assets		21,393			3,656
(Decrease) in accounts payable		(26,532	)		(7,469	)
Increase (decrease) in accrued employment and benefit costs		9,503			(13,921	)
(Decrease) in accrued insurance		(20,289	)		(7,844	)
(Decrease) in customer deposits and advances		(22,847	)		(34,477	)
(Decrease) in accrued interest		(8,565	)		(5,124	)
Increase in other current liabilities		3,942			2,077
(Increase) decrease in other noncurrent assets		(4,092	)		2,048
Increase (decrease) in other noncurrent liabilities		846			(2,077	)

Net cash provided by operating activities		223,498			56,988


Cash flows from investing activities:
Capital expenditures		(13,836	)		(17,301	)
Proceeds from sale of property, plant and equipment		3,965			3,489
Proceeds from sale of discontinued operations		—			53,715

Net cash (used in) provided by investing activities		(9,871	)		39,903


Cash flows from financing activities:
Repayments of short-term borrowings		(110,000	)		—
Proceeds from long-term borrowings		100,000			—
Issuance costs associated with long-term borrowings		(5,543	)		—
Partnership distributions		(79,683	)		(74,854	)

Net cash (used in) financing activities		(95,226	)		(74,854	)


Net increase in cash and cash equivalents		118,401			22,037
Cash and cash equivalents at beginning of period		137,698			96,586

Cash and cash equivalents at end of period	$	256,099		$	118,623

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

SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

(in thousands)

(unaudited)


						Accumulated
						Other			Total
	Number of		Common			Comprehensive			Partners’			Comprehensive
	Common Units		Unitholders			(Loss)			Capital			Income

Balance at September 27, 2008		32,725	$	264,231		$	(44,155	)	$	220,076
Net income				188,119						188,119		$	188,119
Other comprehensive income:
Net unrealized gains on cash flow hedges							231			231			231
Amortization of net actuarial losses and prior service credits into earnings							2,437			2,437			2,437

Comprehensive income												$	190,787


Partnership distributions				(79,683	)					(79,683	)
Common Units issued under Restricted Unit Plan		72
Compensation cost recognized under Restricted Unit Plan, net of forfeitures				1,885						1,885


Balance at June 27, 2009		32,797	$	374,552		$	(41,487	)	$	333,065

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

SUBURBAN PROPANE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(dollars in thousands, except per unit amounts)

(unaudited)

1. Partnership Organization

Suburban Propane Partners, L.P. (the “Partnership”) is a publicly traded Delaware limited partnership principally engaged, through its operating partnership and subsidiaries, in the retail marketing and distribution of propane, fuel oil and refined fuels, as well as the marketing of natural gas and electricity in deregulated markets. In addition, to complement its core marketing and distribution businesses, the Partnership services a wide variety of home comfort equipment, particularly for heating and ventilation. The publicly traded limited partner interests in the Partnership are evidenced by common units traded on the New York Stock Exchange (“Common Units”), with 32,797,020 Common Units outstanding at June 27, 2009. The holders of Common Units are entitled to participate in distributions and exercise the rights and privileges available to limited partners under the Third Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”), adopted on October 19, 2006 following approval by Common Unitholders at the Partnership’s Tri-Annual Meeting and as thereafter amended by the Board of Supervisors on July 31, 2007, pursuant to the authority granted to the Board in the Partnership Agreement. Rights and privileges under the Partnership Agreement include, among other things, the election of all members of the Board of Supervisors and voting on the removal of the general partner.

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

The general partner of both the Partnership and the Operating Partnership is Suburban Energy Services Group LLC (the “General Partner”), a Delaware limited liability company. The General Partner has no economic interest in either the Partnership or the Operating Partnership other than as a holder of 784 Common Units that will remain in the General Partner, no incentive distribution rights are outstanding and the sole member of the General Partner is the Partnership’s Chief Executive Officer.

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”). The operations of Agway Energy consisted of the distribution and marketing of propane, fuel oil and refined fuels, as well as the marketing of natural gas and electricity. The Partnership’s fuel oil and refined fuels, natural gas and electricity and services businesses are structured as limited liability companies owned by the Service Company (collectively referred to as the Corporate Entity) and, as such, are subject to corporate level income tax.

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.

2. Basis of Presentation

Principles of Consolidation. The condensed consolidated financial statements include the accounts of the Partnership, the Operating 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 100% limited partner interest in the Operating Partnership.

The accompanying condensed consolidated financial statements are unaudited and have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”). They include all adjustments that the Partnership considers necessary for a fair statement of the results for the interim periods presented. Such adjustments consist only of normal recurring items, unless otherwise disclosed. These financial statements should be read in conjunction with the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 27, 2008, including management’s discussion and analysis of financial condition and results of operations contained therein. Due to the seasonal nature of the Partnership’s operations, the results of operations for interim periods are not necessarily indicative of the results to be expected for a full year.

Fiscal Period. The Partnership’s fiscal periods typically end on the last Saturday of the quarter.

Revenue Recognition. Sales of propane, fuel oil and refined fuels are recognized at the time product is delivered to the customer. Revenue from the sale of appliances and equipment is recognized at the time of sale or when installation is complete, as applicable. Revenue from repairs, maintenance and other service activities is recognized upon completion of the service. Revenue from 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, as adjusted for amounts delivered but unbilled at the end of each accounting period. Revenue from annually billed tank fees is deferred at the time of billing and recognized on a straight-line basis over one year.

Fair Value Measurements. On September 28, 2008, the Partnership adopted Statement of Financial Accounting Standards (“SFAS”) No. 157, “Fair Value Measurements” (“SFAS 157”). SFAS 157 provides a single definition of fair value and a common framework for measuring fair value as well as new disclosure requirements for fair value measurements used in financial statements. Fair value measurements are based upon the “exit price” concept — the price that would be received to sell an asset or paid to transfer a liability exclusive of any transaction costs in an orderly transaction between market participants — in either the principal market or the most advantageous market. The principal market is the market with the greatest level of activity and volume for the asset or liability. Adoption of SFAS 157 did not impact the Partnership’s financial position, results of operations or cash flows.

SFAS 157 establishes a three-level hierarchy to prioritize the inputs used in the valuation techniques to derive fair values. The basis for fair value measurements for each level within the hierarchy is described below with Level 1 having the highest priority and Level 3 having the lowest.

•

Level 1: Quoted prices in active markets for identical assets or liabilities.

•

Level 2: Quoted prices in active markets for similar assets or liabilities; quoted prices for identical or similar instruments in markets that are not active; and model-derived valuations in which all significant inputs are observable in active markets.

•

Level 3: Valuations derived from valuation techniques in which one or more significant inputs are unobservable.

The Partnership measures the fair value of its options and futures derivative instruments using Level 1 inputs and the fair value of its interest rate swap using Level 2 inputs. See Derivative Instruments and Hedging Activities, below, for disclosure of fair value amounts.

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 depreciation and amortization of long-lived assets, insurance and litigation reserves, environmental reserves, pension and other postretirement benefit liabilities and costs, valuation of derivative instruments, asset valuation assessments, tax valuation allowances, 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.

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

3. Financial Instruments

Cash and Cash Equivalents. The fair value of cash and cash equivalents is not materially different from their carrying amounts because of the short-term nature of these instruments.

Derivative Instruments and Hedging Activities. On December 28, 2008, the Partnership adopted SFAS No. 161 “Disclosures about Derivative Instruments and Hedging Activities — an Amendment of FASB Statement No. 133” (“SFAS 161”). SFAS 161 requires enhanced disclosures about an entity’s objectives for using derivative instruments and related hedged items, how those derivative instruments are accounted for under SFAS 133 (defined below) and its related interpretations and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows.

Commodity Price Risk. Given the retail nature of its operations, the Partnership maintains a certain level of priced physical inventory to ensure its field operations have adequate supply commensurate with the time of year. The Partnership’s strategy is to keep its physical inventory priced relatively close to market for its field operations. The Partnership enters into a combination of exchange-traded futures and option contracts and, in certain instances, over-the-counter forward and option contracts (collectively, “derivative instruments”) to hedge price risk associated with propane and fuel oil physical inventories, as well as future purchases of propane or fuel oil used in its operations and to ensure adequate supply during periods of high demand. Under this risk management strategy, realized gains or losses on derivative instruments will typically offset losses or gains on the physical inventory once the product is sold. All of the Partnership’s derivative instruments are reported on the condensed consolidated balance sheet at their fair values pursuant to SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended (“SFAS 133”). In addition, in the course of normal operations, the Partnership routinely enters into contracts such as forward priced physical contracts for the purchase or sale of propane and fuel oil that, under SFAS 133, qualify for and are designated as normal purchase or normal sale contracts. Such contracts are exempted from the fair value accounting requirements of SFAS 133 and are accounted for at the time product is purchased or sold under the related contract. The Partnership does not use derivative instruments for speculative trading purposes. Market risks associated with 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. Priced on-hand inventory is also reviewed and managed daily as to exposures to changing market prices.

On the date that futures, forward and option contracts are entered into, other than those designated as normal purchases or normal sales, 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 (“OCI”), depending on whether the 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 are recognized in cost of products sold immediately. Changes in the fair value of derivative instruments that are not designated as cash flow hedges, and that do not meet the normal purchase and normal sale exemption under SFAS 133, are recorded within cost of products sold as they occur. Cash flows associated with derivative instruments are reported as operating activities within the condensed consolidated statement of cash flows.

Credit Risk. Exchange-traded futures and options are guaranteed by the New York Mercantile Exchange (“NYMEX”) and, as a result, have minimal credit risk. The Partnership is subject to credit risk with over-the-counter, forward and propane option contracts to the extent the counterparties do not perform. The Partnership evaluates the financial condition of each counterparty with which it conducts business and establish credit limits to reduce exposure to the risk of non-performance by its counterparties.

Interest Rate Risk. A portion of the Partnership’s borrowings bear interest at prevailing interest rates based upon, at the Operating Partnership’s option, LIBOR plus an applicable margin or the base rate, defined as the higher of the Federal Funds Rate plus ¹/2 of 1% or the agent bank’s prime rate, or LIBOR plus 1%, plus the applicable margin. The applicable margin is dependent on the level of the Partnership’s total leverage (the ratio of total debt to income before deducting interest expense, income taxes, depreciation and amortization (“EBITDA”)). 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. The interest rate swap is being accounted for under SFAS 133 and the Partnership has designated it 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.

The following summarizes the Partnership’s open derivative instruments as of June 27, 2009:


Transaction Type	(gallons in thousands)
Options		5,056
Futures		17,220

The following summarizes the gross fair value of the Partnership’s derivative instruments and their location in the condensed consolidated balance sheet as of June 27, 2009:


	Asset Derivatives			Liability Derivatives
	Location	Fair Value		Location	Fair Value
Derivatives designated as hedging instruments under SFAS 133:
Interest rate swap				Other liabilities	$	2,969

					$	2,969

Derivatives not designated as hedging instruments under SFAS 133:
Options	Other current assets	$	6,216	Other current liabilities	$	3,507
	Other assets		504	Other liabilities		328

Futures	Other current assets		350	Other current liabilities		1,503

		$	7,070		$	5,338

The effect of the Partnership’s derivative instruments on the condensed consolidated statement of operations for the three and nine months ended June 27, 2009 and June 28, 2008 are as follows:

Three months ended June 27, 2009

Three months ended June 28, 2008

Derivatives in

Gains (Losses) Reclassified

SFAS 133 Cash

Amount of Gains

from Accumulated OCI into

Amount of Gains

from Accumulated OCI into

Flow Hedging

(Losses) Recognized

Income (Effective Portion)

(Losses) Recognized

Income (Effective Portion)

Relationships

in OCI (Effective Portion)

Location

Amount

in OCI (Effective Portion)

Location

Amount

Interest rate swap

816

Interest expense

—

2,650

Interest expense

—

816

—

2,650

—

Derivatives Not

Amount of

Designated as

Unrealized

Hedging

Location of Gains

Gains (Losses)

Location of Gains

Gains (Losses)

Instruments under

(Losses) Recognized

Recognized in

(Losses) Recognized in

Recognized in

SFAS 133

in Income

Income

Options

Cost of goods sold

(1,220

)

Cost of goods sold

(737

)

Futures

Cost of goods sold

(4,928

)

Cost of goods sold

5,432

(6,148

)

4,695


	Nine months ended June 27, 2009					Nine months ended June 28, 2008
Derivatives in			Gains (Losses) Reclassified						Gains (Losses) Reclassified
SFAS 133 Cash	Amount of Gains		from Accumulated OCI into			Amount of Gains			from Accumulated OCI into
Flow Hedging	(Losses) Recognized		Income (Effective Portion)			(Losses) Recognized			Income (Effective Portion)
Relationships	in OCI (Effective Portion)		Location	Amount		in OCI (Effective Portion)			Location	Amount


Interest rate swap	$	231	Interest expense	$	—	$	(2,473	)	Interest expense	$	—

	$	231		$	—	$	(2,473	)		$	—

Derivatives Not

Amount of

Designated as

Unrealized

Hedging

Location of Gains

Gains (Losses)

Location of Gains

Gains (Losses)

Instruments under

(Losses) Recognized

Recognized in

(Losses) Recognized

Recognized in

SFAS 133

in Income

Income

in Income

Income

Options

Cost of goods sold

327

Cost of goods sold

(69

)

Futures

Cost of goods sold

(1,159

)

Cost of goods sold

(254

)

(832

)

(323

)

Bank Debt and Senior Notes. The fair value of the Revolving Credit Facility (defined below) approximates the carrying value since the interest rates are periodically adjusted to reflect market conditions. Based upon quoted market prices, the fair value of the Partnership’s 6.875% Senior Notes was $392,063 as of June 27, 2009.

4. Discontinued Operations

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, on October 2, 2007, the Operating Partnership completed the sale of its Tirzah, South Carolina underground granite propane storage cavern, and associated 62-mile pipeline, for $53,715 in cash, after taking into account certain adjustments. The 57.5 million gallon underground storage cavern is connected to the Dixie Pipeline and provides propane storage for the eastern United States. As part of the agreement, the Operating Partnership entered into a long-term storage arrangement, not to exceed 7 million propane gallons, with the purchaser of the cavern that will enable the Operating Partnership to continue to meet the needs of its retail operations, consistent with past practices. As a result of this sale, a gain of $43,707 was reported as a gain from the disposal of discontinued operations in the Partnership’s condensed consolidated statement of operations for the first quarter of fiscal 2008.

5. Inventories

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


	As of
	June 27,		September 27,
	2009		2008

Propane, fuel oil and refined fuels	$	54,552	$	76,036
Natural gas		—		283
Appliances and related parts		3,182		3,503

	$	57,734	$	79,822

6. Goodwill and Other Intangible Assets

Goodwill represents the excess of the purchase price over the fair value of net assets of businesses acquired. In accordance with SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”), goodwill is not amortized. 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. 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.

During the nine months ended June 27, 2009 and June 28, 2008, the Partnership reversed $1,380 and $1,277, respectively, of the deferred tax asset valuation allowance, which was established through purchase accounting for the Agway Acquisition, as a reduction of goodwill. These adjustments resulted from the utilization of a portion of the net operating losses established in purchase accounting for the Agway Acquisition.

Other intangible assets consist of the following:


	As of
	June 27,			September 27,
	2009			2008

Customer lists	$	22,316		$	22,316
Tradenames		1,499			1,499
Other		2,117			2,117

	$	25,932		$	25,932


Less: accumulated amortization
Customer lists	$	(10,105	)	$	(8,632	)
Tradenames		(825	)		(712	)
Other		(649	)		(570	)

		(11,579	)		(9,914	)

	$	14,353		$	16,018

Aggregate amortization expense related to other intangible assets for the three and nine months ended June 27, 2009 was $555 and $1,665, respectively, and $555 and $1,669 for the three and nine months ended June 28, 2008, respectively.

Aggregate amortization expense related to other intangible assets for the remainder of fiscal 2009 and for each of the five succeeding fiscal years as of June 27, 2009 is as follows: 2009 — $555; 2010 — $2,205; 2011 — $2,205; 2012 — $1,730; 2013 — $1,572 and 2014 — $1,237.

7. Income Per Common Unit

Computations of earnings per Common Unit are performed in accordance with SFAS No. 128 “Earnings per Share” (“SFAS 128”). Basic income per Common Unit was computed by dividing net income by the weighted average number of outstanding Common Units and restricted units granted under the 2000 Restricted Unit Plan, defined below, to retirement-eligible grantees. Diluted income per Common Unit was computed by dividing net income by the weighted average number of outstanding Common Units and unvested restricted units granted under the 2000 Restricted Unit Plan.

In computing diluted income per Common Unit, weighted average units outstanding used to compute basic income per Common Unit were increased by 177,176 and 222,104 units for the nine months ended June 27, 2009, and June 28, 2008, respectively, to reflect the potential dilutive effect of the unvested restricted units outstanding using the treasury stock method. Diluted loss per unit for the three months ended June 27, 2009 and June 28, 2008 does not include unvested Restricted Units as their effect would be anti-dilutive.

8. Long-Term Borrowings

Long-term borrowings consist of the following:


	As of
	June 27,		September 27,
	2009		2008
Senior Notes, 6.875%, due December 15, 2013, net of unamortized discount of $1,053 and $1,228, respectively	$	423,947	$	423,772
Term Loan, 6.29% to 7.16%, redeemed June 26, 2009		—		110,000
Revolving Credit Facility, due June 25, 2013		100,000		—

		523,947		533,772
Less: current portion of Term Loan		—		2,000

	$	523,947	$	531,772

The Partnership and its subsidiary, Suburban Energy Finance Corporation, have issued $425,000 aggregate principal amount of Senior Notes (the “2003 Senior Notes”) with an annual interest rate of 6.875%. The Partnership’s obligations under the 2003 Senior Notes are unsecured and rank senior in right of payment to any future subordinated indebtedness and equally in right of payment with any future senior indebtedness. The 2003 Senior Notes are structurally subordinated to, which means they rank effectively behind, any debt and other liabilities of the Operating Partnership. The 2003 Senior Notes mature on December 15, 2013 and require semi-annual interest payments in June and December. The Partnership is permitted to redeem some or all of the 2003 Senior Notes any time on or after December 15, 2008 at redemption prices specified in the indenture governing the 2003 Senior Notes. In addition, in the event of a change of control of the Partnership, as defined in the indenture governing the 2003 Senior Notes, the Partnership must offer to repurchase the notes at 101% of the principal amount repurchased, if the holders of the notes exercise the right of repurchase.

On June 26, 2009, the Operating Partnership executed a Credit Agreement (the “Credit Agreement”) to provide a four-year $250,000 revolving credit facility (the “Revolving Credit Facility”). The Credit Agreement replaces the Operating Partnership’s previous credit facility, which provided for a $108,000 term loan (the “Term Loan”) and a separate $175,000 working capital facility both of which, as amended, were scheduled to mature in March 2010. Borrowings under the Revolving Credit Facility may be used for general corporate purposes, including working capital, capital expenditures and acquisitions until maturity on June 25, 2013. The Operating Partnership has the right to prepay loans under the Revolving Credit Facility, in whole or in part, without penalty at any time prior to maturity. At closing, the Operating Partnership borrowed $100,000 under the Revolving Credit Facility and, along with cash on hand, repaid the $108,000 then outstanding under the Term Loan and terminated the previous credit facility.

Borrowings under the Revolving Credit Facility bear interest at prevailing interest rates based upon, at the Operating Partnership’s option, LIBOR plus the applicable margin or the base rate, defined as the higher of the Federal Funds Rate plus ¹/2 of 1%, the agent bank’s prime rate, or LIBOR plus 1%, plus in each case the applicable margin. The applicable margin is dependent upon the Partnership’s ratio of total debt to EBITDA on a consolidated basis, as defined in the Revolving Credit Facility. As of June 27, 2009, the interest rate for the Revolving Credit Facility was approximately 4.1% and will be reset at the end of each calendar quarter.

The Partnership acts as a guarantor with respect to the obligations of the Operating Partnership under the Credit Agreement pursuant to the terms and conditions set forth therein. The obligations under the Credit Agreement are secured by liens on substantially all of the personal property of the Partnership, the Operating Partnership and their subsidiaries, as well as mortgages on certain significant properties.

In connection with the Revolving Credit Facility, the Operating Partnership amended its existing interest rate swap agreement, which has a termination date of March 31, 2010, to reduce the notional amount to $100,000 from $108,000. The Operating Partnership will pay a fixed interest rate of 4.66% to the issuing lender on the notional principal amount outstanding, 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 Revolving Credit Facility 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. The Revolving Credit Facility contains certain financial covenants (a) requiring the consolidated interest coverage ratio, as defined, of the Partnership to be not less than 2.5 to 1.0 as of the end of any fiscal quarter; (b) prohibiting the total consolidated leverage ratio, as defined, of the Partnership from being greater than 4.5 to 1.0 as of the end of any fiscal quarter; and (c) prohibiting the senior secured consolidated leverage ratio, as defined, of the Operating Partnership from being greater than 3.0 to 1.0 as of the end of any fiscal quarter. Under the 2003 Senior Note indenture, the Partnership is generally permitted to make cash distributions equal to available cash, as defined, as of the end of the immediately preceding quarter, if no event of default exists or would exist upon making such distributions, and the Partnership’s consolidated fixed charge coverage ratio, as defined, is greater than 1.75 to 1. The Partnership and the Operating Partnership were in compliance with all covenants and terms of the 2003 Senior Notes and the Revolving Credit Facility as of June 27, 2009.

Debt origination costs representing the costs incurred in connection with the placement of, and the subsequent amendment to, long-term borrowings are capitalized and amortized on a straight-line basis over the term of the respective debt agreements. Other assets at June 27, 2009 and September 27, 2008 include debt origination costs with a net carrying amount of $9,035 and $4,902, respectively. Aggregate amortization expense related to deferred debt origination costs included within interest expense for the three months ended June 27, 2009 and June 28, 2008 was $746 and $332, respectively, and $1,410 and $996 for the nine months ended June 27, 2009 and June 28, 2008, respectively. Unamortized debt origination costs of $414 associated with the previous credit facility were written-off in the third quarter of fiscal 2009.

The aggregate amounts of long-term debt maturities subsequent to June 27, 2009 are as follows: fiscal 2009 through fiscal 2012 — $0 and 2013 — $525,000.

Under the previous credit facility, proceeds from the sale, transfer or other disposition of any asset of the Operating Partnership, other than the sale of inventory in the ordinary course of business, in excess of $15,000 must be used to acquire productive assets within twelve months of receipt of the proceeds. Any proceeds not used within twelve months of receipt to acquire productive assets were required to be used to prepay the outstanding principal of the Term Loan. On September 26, 2008 and November 10, 2008, the Operating Partnership prepaid $15,000 and $2,000, respectively, on the Term Loan with the net proceeds from the sale of the Tirzah storage facility that were not used to acquire productive assets within twelve months of receipt.

9. Distributions of Available Cash

The Partnership makes distributions to its limited partners no later than 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.

On July 22, 2009, the Board of Supervisors declared a quarterly distribution of $0.825 per Common Unit, or $3.30 per Common Unit on an annualized basis, in respect of the third quarter of fiscal 2009, payable on August 11, 2009 to holders of record on August 4, 2009. The annualized distribution represents an increase of $0.04 per Common Unit from the previous distribution rate, and a growth rate of 3.1% compared to the third quarter of fiscal 2008.

10. Unit-Based Compensation Arrangements

The Partnership accounts for its unit-based compensation arrangements in accordance with revised SFAS No. 123, “Share-Based Payment” (“SFAS 123R”), which requires the recognition of compensation cost over the respective service period for employee services received in exchange for an award of equity or equity-based compensation based on the grant date fair value of the award, as well as the measurement of liability awards under a unit-based payment arrangement based on remeasurement of the award’s fair value at the conclusion of each quarterly reporting period until the date of settlement, taking into consideration the probability that the performance conditions will be satisfied. The Partnership has historically recognized unearned compensation associated with awards under its 2000 Restricted Unit Plan ratably to expense over the vesting period based on the fair value of the award on the grant date and has historically recognized compensation cost and the associated unearned compensation liability for equity-based awards under its Long-Term Incentive Plan consistent with the requirements of SFAS 123R.

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

During the nine months ended June 27, 2009, the Partnership awarded 68,799 Restricted Units under the 2000 Restricted Unit Plan at an aggregate grant date fair value of $1,245. The following is a summary of activity in the 2000 Restricted Unit Plan:


				Weighted
				Average Grant
				Date Fair Value
	Units			Per Unit
Outstanding September 27, 2008		446,515		$	30.57
Awarded		68,799			18.09
Forfeited		(16,046	)		35.40
Issued		(71,637	)		27.81

Outstanding June 27, 2009		427,631		$	28.85

As of June 27, 2009, $5,398 of compensation cost related to unvested Restricted Units awarded under the 2000 Restricted Unit Plan remains to be recognized in future periods. Compensation cost associated with unvested awards is expected to be recognized over a weighted-average period of 1.7 years. Compensation expense recognized under the 2000 Restricted Unit Plan, net of forfeitures, for the three and nine months ended June 27, 2009 was $644 and $1,885, respectively, and $817 and $1,503 for the three and nine months ended June 28, 2008, respectively.

Long-Term Incentive Plan. The Partnership has a non-qualified, unfunded long-term incentive plan for officers and key employees (“LTIP-2”) which provides for payment, in the form of cash, of an award of equity-based compensation at the end of a three-year performance period. The level of compensation earned under LTIP-2 is based on the market performance of the Partnership’s Common Units on the basis of total return to Unitholders (“TRU”) compared to the TRU of a predetermined peer group consisting solely of other master limited partnerships, approved by the Compensation Committee of the Board of Supervisors, over the same three-year performance period. As a result of the quarterly remeasurement of the liability for awards under LTIP-2, compensation expense for the three and nine months ended June 27, 2009 was $1,639 and $3,591, respectively, and $1,217 and $1,635 for the three and nine months ended June 28, 2008, respectively. As of June 27, 2009 and September 27, 2008, the Partnership had a liability included within accrued employment and benefit costs (or other liabilities, as applicable) of $6,746 and $5,921, respectively, related to estimated future payments under LTIP-2.

11. Commitments and Contingencies

Self-Insurance. The Partnership is self-insured for general and product, workers’ compensation and automobile liabilities up to predetermined thresholds above which third party insurance applies. As of June 27, 2009 and September 27, 2008, the Partnership had accrued insurance liabilities of $52,744 and $73,033, respectively, representing the total estimated losses under these self-insurance programs. The Partnership is also involved in various legal actions that have arisen in the normal course of business, including those relating to commercial transactions and product liability. Management believes, based on the advice of legal counsel, that the ultimate resolution of these matters will not have a material adverse effect on the Partnership’s financial position or future results of operations, after considering its self-insurance reserves for known and unasserted claims, as well as existing insurance policies in force. For the portion of the estimated self-insurance liability that exceeds insurance deductibles, the Partnership records an asset within other assets (or other current assets, as applicable) related to the amount of the liability expected to be covered by insurance which amounted to $16,139 and $38,825 as of June 27, 2009 and September 27, 2008, respectively.

During the first quarter of fiscal 2009, the Partnership settled a claim involving alleged product liability for approximately $30,000. The settlement was covered by insurance above the level of the Partnership’s deductible. As a result of this settlement, in which the Partnership denied any liability, the Partnership increased the portion of its estimated self-insurance liability that exceeded the insurance deductible and established a corresponding asset of $30,000 as of September 27, 2008 to accrue for the settlement and subsequent reimbursement from the Partnership’s third party insurance carrier. During fiscal 2009, the Partnership fully paid the $30,000 to the claimants in this matter and was reimbursed for the same amount from the Partnership’s third party insurance carrier.

12. 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 2016. 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, was approximately $18,339 as of June 27, 2009. The fair value of residual value guarantees for outstanding operating leases was de minimis as of June 27, 2009 and September 27, 2008.

13. Pension Plans and Other Postretirement Benefits

The following table provides the components of net periodic benefit costs for the three and nine months ended June 27, 2009 and June 28, 2008:


	Pension Benefits
	Three Months Ended						Nine Months Ended
	June 27,			June 28,			June 27,			June 28,
	2009			2008			2009			2008

Service Cost	$	—		$	—		$	—		$	—
Interest cost		2,372			2,187			7,116			6,562
Expected return on plan assets		(2,301	)		(2,270	)		(6,904	)		(6,811	)
Amortization of prior service costs		—			—			—			—
Recognized net actuarial loss		1,012			844			3,037			2,531

Net periodic benefit cost	$	1,083		$	761		$	3,249		$	2,282


	Postretirement Benefits
	Three Months Ended						Nine Months Ended
	June 27,			June 28,			June 27,			June 28,
	2009			2008			2009			2008

Service Cost	$	1		$	2		$	3		$	6
Interest cost		345			350			1,036			1,049
Expected return on plan assets		—			—			—			—
Amortization of prior service costs		(122	)		(122	)		(367	)		(367	)
Recognized net actuarial loss		(78	)		—			(233	)		—

Net periodic benefit cost	$	146		$	230		$	439		$	688

There are no projected minimum employer contribution requirements under Internal Revenue Service Regulations for fiscal 2009 under our defined benefit pension plan. The projected annual contribution requirements related to the Partnership’s postretirement health care and life insurance benefit plan for fiscal 2009 is $1,923, of which $1,324 has been contributed during the nine months ended June 27, 2009.

14. 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, as a separate legal entity, and the Operating Partnership are not subject to income tax at the Partnership level. Rather, the taxable income or loss attributable to the Partnership, as a separate legal entity, and to the Operating Partnership, which may vary substantially from the income before income taxes, reported by the Partnership in the condensed consolidated statement of operations, are 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 basis in the Partnership.

The Partnership’s fuel oil and refined fuels, natural gas and electricity, and service businesses are structured collectively as a corporate entity and, as such, are subject to corporate level federal and state income taxes. However, because the Corporate Entity has experienced operating losses in recent years, a full valuation allowance has been provided against the deferred tax assets. The conclusion that a full valuation allowance is necessary was based upon an analysis of all available evidence, both negative and positive at the balance sheet date, which, taken as a whole, indicates that it is more likely than not that sufficient future taxable income will not be available to utilize the Partnership’s deferred tax assets. Management’s periodic reviews include, among other things, the nature and amount of the taxable income and expense items, the expected timing when assets will be used or liabilities will be required to be reported and the reliability of historical profitability of businesses expected to provide future earnings. Furthermore, management considered tax-planning strategies it could use to increase the likelihood that the deferred tax assets will be realized.

As a result of the profitability of the Corporate Entity during the first nine months of fiscal 2009 and fiscal 2008, it reported taxable income which enabled utilization of net operating losses to offset the current cash tax liability. Utilization of these net operating losses resulted in a $1,380 and $1,277 deferred tax provision during the first nine months of fiscal 2009 and fiscal 2008, respectively, and a corresponding reversal of a portion of the valuation allowance established in purchase accounting for the Agway Acquisition, which reduced goodwill.

15. Segment Information

The Partnership manages and evaluates its operations in six segments, four of which are reportable segments: Propane, Fuel Oil and Refined Fuels, Natural Gas and Electricity and Services. The chief operating decision maker evaluates performance of the operating segments using a number of performance measures, including gross margins and income before interest expense and provision for income taxes (operating profit). Costs excluded from these profit measures 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 condensed consolidated statements of operations. In addition, certain costs associated with field operations support that are reported in operating expenses in the condensed 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 otherwise the same as those described in the summary of significant accounting policies Note in the Partnership’s Annual Report on Form 10-K for the fiscal year ended September 27, 2008.

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

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

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

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


	Three Months Ended						Nine Months Ended
	June 27,			June 28,			June 27,			June 28,
	2009			2008			2009			2008
Revenues:
Propane	$	139,571		$	216,999		$	750,392		$	946,700
Fuel oil and refined fuels		23,091			55,262			142,420			247,609
Natural gas and electricity		12,147			22,507			66,521			84,693
Services		8,321			9,184			30,574			34,752
All other		1,242			1,524			3,005			3,928

Total revenues	$	184,372		$	305,476		$	992,912		$	1,317,682


Income (loss) before interest expense and income taxes:
Propane	$	28,090		$	26,148		$	255,251		$	198,634
Fuel oil and refined fuels		(4,781	)		(9,644	)		19,078			1,161
Natural gas and electricity		2,530			1,108			11,552			8,546
Services		(3,636	)		(4,546	)		(9,521	)		(10,901	)
All other		(517	)		20			(1,384	)		(403	)
Corporate		(17,893	)		(17,466	)		(55,760	)		(45,253	)

Total income (loss) before interest expense and income taxes		3,793			(4,380	)		219,216			151,784

Reconciliation to (loss) income from continuing operations:
Interest expense, net		10,068			9,524			28,913			27,330
Provision for (benefit from) income taxes		1,160			(157	)		2,184			1,956

(Loss) income from continuing operations	$	(7,435	)	$	(13,747	)	$	188,119		$	122,498


Depreciation and amortization:
Propane	$	4,072		$	3,910		$	11,704		$	11,692
Fuel oil and refined fuels		1,485			839			3,125			2,548
Natural gas and electricity		252			252			756			756
Services		71			78			223			233
All other		75			16			108			63
Corporate		1,758			2,064			5,951			6,033

Total depreciation and amortization	$	7,713		$	7,159		$	21,867		$	21,325


	As of
	June 27,			September 27,
	2009			2008
Assets:
Propane	$	682,337		$	746,281
Fuel oil and refined fuels		81,566			70,548
Natural gas and electricity		17,766			23,658
Services		2,254			2,841
All other		965			1,234
Corporate		378,398			279,132
Eliminations		(87,981	)		(87,981	)

Total assets	$	1,075,305		$	1,035,713

16. Recently Issued Accounting Pronouncements

In December 2008, the FASB issued an FSP on Statement 132(R)-1, “Employers’ Disclosure about Postretirement Benefit Plan Assets” (“FSP 132(R)-1”), which amends SFAS No. 132(R) to require more detailed disclosures about employers’ pension plan assets. These new disclosures will include more information on investment strategies, major categories of plan assets, concentrations of risk within plan assets and valuation techniques used to measure the fair value of plan assets. FSP 132(R)-1 is effective for fiscal years ending after December 15, 2009, which will be the Partnership’s 2010 fiscal year ending September 25, 2010. Since FSP 132(R)-1 only addresses disclosure requirements, its adoption is not expected to have an impact on the Partnership’s consolidated financial position, results of operations and cash flows.

In December 2007, the FASB issued a revised SFAS No. 141 “Business Combinations” (“SFAS 141R”), which, among other things, requires an entity to recognize acquired assets, liabilities assumed and any noncontrolling interest at their respective fair values as of the acquisition date, clarifies how goodwill involved in a business combination is to be recognized and measured, as well as requires the expensing of acquisition-related costs as incurred. SFAS 141R is effective for business combinations entered into in fiscal years beginning on or after December 15, 2008, which will be the Partnership’s 2010 fiscal year beginning September 27, 2009, with early adoption prohibited.

17. Subsequent Events

Effective for the period ended June 27, 2009 the Partnership adopted SFAS No. 165, “Subsequent Events” (“SFAS 165”), requiring entities to disclose its assessment of events occurring after the balance sheet date but before financial statements are issued (or available to be issued) that may or may not have an impact on the reported period’s financial statements.

On July 22, 2009, the Partnership held its Tri-Annual Meeting of its Limited Partners during which, amongst other things, the Suburban Propane Partners, L.P. 2009 Restricted Unit Plan (the “2009 Restricted Unit Plan”) was adopted. The 2009 Restricted Unit Plan authorizes the issuance of Common Units to executives, managers and other employees and members of the Board of Supervisors of the Partnership. More specifically, awards of up to an aggregate 1,200,000 Common Units may be granted at the discretion of the Compensation Committee of the Partnership’s Board of Supervisors through July 31, 2019, under terms similar to those described in connection with the 2000 Restricted Unit Plan in Note 10, above. The adoption of the 2009 Restricted Unit Plan did not have an impact on the Partnership’s financial statements as of and for the period ended June 27, 2009.

The Partnership has evaluated events and transactions through August 6, 2009, the date the financial statements were issued and filed with the SEC. No other events have occurred subsequent to June 27, 2009 through August 6, 2009 that would have an impact on the financial statements as of and for the period ended June 27, 2009.


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

The following is a discussion of the financial condition and results of operations of the Partnership as of and for the three and nine months ended June 27, 2009. The discussion should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations and the historical consolidated financial statements and notes thereto included in the Annual Report on Form 10-K for the fiscal year ended September 27, 2008.

Executive Overview

The following are factors that regularly affect our operating results and financial condition. In addition, our business is subject to the risks and uncertainties described in Item 1A of this Quarterly Report as well as those included in the Annual Report on Form 10-K for the fiscal year ended September 27, 2008.

Product Costs and Supply

The level of profitability in the retail propane, fuel oil, natural gas and electricity businesses is largely dependent on the difference between retail sales price and product cost. The unit cost of our products, particularly propane, fuel oil and natural gas, is subject to volatility as a result of product supply or other market conditions, including, but not limited to, economic and political factors impacting crude oil and natural gas supply or pricing. We enter into product supply contracts that are generally one-year agreements subject to annual renewal, and also purchase product on the open market. We attempt to reduce price risk by pricing product on a short-term basis. Our propane supply contracts typically provide for pricing based upon index formulas using the posted prices established at major supply points such as Mont Belvieu, Texas, or Conway, Kansas (plus transportation costs) at the time of delivery.

To supplement our annual purchase requirements, we may utilize forward fixed price purchase contracts to acquire a portion of the propane that we resell to our customers, which allows us to manage our exposure to unfavorable changes in commodity prices and to assure adequate physical supply. The percentage of contract purchases, and the amount of supply contracted for under forward contracts at fixed prices, will vary from year to year based on market conditions.

Product cost changes can occur rapidly over a short period of time and can impact profitability. There is no assurance that we will be able to pass on product cost increases fully or immediately, particularly when product costs increase rapidly. Therefore, average retail sales prices can vary significantly from year to year as product costs fluctuate with propane, fuel oil, crude oil and natural gas commodity market conditions. In addition, in periods of sustained higher commodity prices, as has been experienced over the past several fiscal years, retail sales volumes have been negatively impacted by customer conservation efforts.

Seasonality

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

Weather

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

Hedging and Risk Management Activities

We engage in hedging and risk management activities to reduce the effect of price volatility on our product costs and to ensure the availability of product during periods of short supply. We enter into propane forward and option agreements with third parties, and use fuel oil and crude oil futures and option contracts traded on the New York Mercantile Exchange (“NYMEX”), to purchase and sell fuel oil and crude oil at fixed prices in the future. The majority of the futures, forward and option agreements are used to hedge price risk associated with propane and fuel oil physical inventory, as well as, in certain instances, forecasted purchases of propane or fuel oil. Forward contracts are generally settled physically at the expiration of the contract and futures are generally settled in cash at the expiration of the contract. Although we use derivative instruments to reduce the effect of price volatility associated with priced physical inventory and forecasted transactions, we do not use derivative instruments for speculative trading purposes. Risk management activities are monitored by an internal Commodity Risk Management Committee, made up of five members of management and reporting to our Audit Committee, through enforcement of our Hedging and Risk Management Policy.

Critical Accounting Policies and Estimates

Our significant accounting policies are summarized in Note 2, “Summary of Significant Accounting Policies,” included within the Notes to Consolidated Financial Statements section of our Annual Report on Form 10-K for the fiscal year ended September 27, 2008.

Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated, requiring management to make certain assumptions with respect to values or conditions that cannot be known with certainty at the time the financial statements are prepared. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We are also subject to risks and uncertainties that may cause actual results to differ from estimated results. Estimates are used when accounting for depreciation and amortization of long-lived assets, employee benefit plans, self-insurance and litigation reserves, environmental reserves, allowances for doubtful accounts, asset valuation assessments and valuation of derivative instruments. We base our estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known to us. Management has reviewed these critical accounting estimates and related disclosures with the Audit Committee of our Board of Supervisors.

Results of Operations and Financial Condition

Consistent with the seasonal nature of the propane and fuel oil businesses, we typically experience a net loss in the third quarter. Net loss for the three months ended June 27, 2009 narrowed to $7.4 million, or $0.23 per Common Unit, compared to a net loss of $13.7 million, or $0.42 per Common Unit, in the prior year third quarter. Earnings before interest, taxes, depreciation and amortization (“EBITDA”) for the third quarter of fiscal 2009 amounted to $11.5 million, compared to $2.8 million in the prior year third quarter. EBITDA for the third quarter of fiscal 2009 included a $6.1 million unrealized (non-cash) loss representing the net change in the fair value of derivative instruments during the period (reported within cost of products sold), compared to a $4.7 million unrealized (non-cash) gain in the prior year third quarter resulting in a $10.8 million decrease in EBITDA in the third quarter of fiscal 2009 compared to the prior year third quarter. Excluding the impact of non-cash adjustments on derivative instruments, Adjusted EBITDA (as defined and reconciled below) was $17.7 million for the third quarter of fiscal 2009, an increase of $19.6 million compared to a loss of $1.9 million in the prior year third quarter.

The improvement in Adjusted EBITDA for the third quarter of fiscal 2009 compared to the prior year third quarter was driven primarily by higher operating margins, expense reductions gained through operating efficiencies and the absence of $14.5 million in realized losses from risk management activities that occurred in the third quarter of fiscal 2008 at the height of last year’s rise in commodity prices. The economic recession continued to negatively affect sales volumes in the propane and refined fuels segments, especially in the commercial and industrial sectors, which account for a greater concentration of sales volumes after the heating season. With the increased level of earnings during the first three quarters of fiscal 2009 compared to the first three quarters of the prior year, coupled with lower working capital requirements from the generally lower commodity price environment, we ended the third quarter of fiscal 2009 with $256.1 million of cash on hand.

Retail propane gallons sold in the third quarter of fiscal 2009 decreased 10.2 million gallons, or 14.3%, to 61.2 million gallons compared to 71.4 million gallons in the prior year third quarter. Sales of fuel oil and other refined fuels decreased 2.9 million gallons, or 23.3%, to 9.7 million gallons during the third quarter of fiscal 2009 compared to 12.6 million gallons in the prior year third quarter. Lower volumes in both segments were primarily attributed to declines in commercial and industrial volumes resulting from the recession and, to a lesser extent, continued customer conservation.

In the commodities market, average posted prices for propane of $0.727 per gallon and for fuel oil of $1.556 per gallon during the third quarter of fiscal 2009 were 57.2% and 56.0%, respectively, lower than the prior year third quarter. The decline in commodity prices contributed to a reduction in our product costs, which resulted in an increase in our retail propane and fuel oil unit margins for the third quarter of fiscal 2009 compared to the prior year third quarter. In addition, as discussed above, the rapidly rising commodity price environment during the third quarter of fiscal 2008 contributed to $14.5 million in realized losses from our risk management activities that were not fully offset by sales of the physical product.

The proactive steps we have taken in prior years to create a more efficient and cost effective operating structure continue to produce cost savings and have contributed to the overall strength of our cash flow and financial position. Combined operating and general and administrative expenses of $85.4 million for the third quarter of fiscal 2009 decreased $4.3 million, or 4.8%, compared to the prior year third quarter primarily due to continued savings in payroll and vehicles expenses, partially offset by higher variable compensation attributable to higher earnings.

From a cash flow perspective, we continue to fund working capital requirements from cash on hand. During the third quarter of fiscal 2009, we generated $64.5 million in cash flow from operations. We ended the third quarter of fiscal 2009 with $256.1 million in cash on hand and are well positioned as we advance into the fourth quarter of the fiscal year. In addition, since the end of the third quarter of the prior year, we have reduced outstanding debt by $25.0 million. On the strength of these earnings and cash flows, our Board of Supervisors declared the twenty-second increase (since our recapitalization in 1999) in our quarterly distribution from $0.815 to $0.825 per Common Unit. The distribution equates to $3.30 per Common Unit annualized, an increase of $0.04 per Common Unit from the previous distribution rate, and a growth rate of 3.1% compared to the third quarter of fiscal 2008.

Looking ahead to the remainder of fiscal 2009, we expect that the economic recession and volatile commodity price environment will continue to present challenges in each of our markets that will continue to affect customer buying habits, thus having a possible negative impact on sales volumes. Nonetheless, we believe that our flexible cost structure, focus on operating efficiencies and financial strength are all factors that will help us effectively manage through the challenging operating environment.

Our anticipated cash requirements for the remainder of fiscal 2009 include: (i) maintenance and growth capital expenditures of approximately $11.2 million; (ii) interest payments of approximately $3.3 million; and (iii) cash distributions of approximately $27.1 million to our Common Unitholders based on the most recently increased quarterly distribution rate of $0.825 per Common Unit. Based on our current estimates of cash flow from operations and our cash position at the end of the third quarter of fiscal 2009, we do not anticipate the need to borrow under our credit facility to meet our working capital requirements for the remainder of fiscal 2009. On June 26, 2009, we successfully completed a new $250.0 million senior secured revolving credit facility (“Revolving Credit Facility”). The new four-year Revolving Credit Facility provides for $250.0 million of revolving lines of credit to replace our previous credit agreement, which consisted of a $175.0 million working capital facility and a separate $108.0 million term loan, both of which were set to mature in March 2010. At closing we borrowed $100.0 million under the Revolving Credit Facility and, along with cash on hand, repaid the $108.0 million previously outstanding on the term loan facility. As of June 27, 2009, there was unused borrowing capacity under the Revolving Credit Facility of $92.8 million after considering outstanding letters of credit of $57.2 million.

Three Months Ended June 27, 2009 Compared to Three Months Ended June 28, 2008

Revenues


	Three Months Ended
	June 27,		June 28,					Percent
(Dollars in thousands)	2009		2008		Decrease			Decrease
Revenues
Propane	$	139,571	$	216,999	$	(77,428	)		(35.7	%)
Fuel oil and refined fuels		23,091		55,262		(32,171	)		(58.2	%)
Natural gas and electricity		12,147		22,507		(10,360	)		(46.0	%)
Services		8,321		9,184		(863	)		(9.4	%)
All other		1,242		1,524		(282	)		(18.5	%)

Total revenues	$	184,372	$	305,476	$	(121,104	)		(39.6	%)

Total revenues decreased $121.1 million, or 39.6%, to $184.4 million for the three months ended June 27, 2009 compared to $305.5 million for the three months ended June 28, 2008 due to lower average selling prices associated with lower product costs, and, to a lesser extent, lower volumes. Volumes were lower than the prior year third quarter due to the negative impact of adverse economic conditions, particularly on our commercial and industrial accounts, as well as ongoing customer conservation efforts and the unfavorable impact of warmer temperatures. On an overall basis, temperatures in our service territories were 7% warmer than normal levels during the third quarter of fiscal 2009 and 4% warmer than the prior year third quarter.

Revenues from the distribution of propane and related activities of $139.6 million in the third quarter of fiscal 2009 decreased $77.4 million, or 35.7%, compared to $217.0 million in the prior year third quarter, primarily due to lower average selling prices, and, to a lesser extent, lower volumes, particularly in our commercial and industrial accounts. Average propane selling prices in the third quarter of fiscal 2009 decreased 23.3% compared to the prior year third quarter due to lower product costs, thereby having a negative impact on revenues. Retail propane gallons sold in the third quarter of fiscal 2009 decreased 10.2 million gallons, or 14.3%, to 61.2 million gallons from 71.4 million gallons in the prior year third quarter. The volume decline was primarily attributable to lower commercial and industrial volumes, which account for a greater concentration of sales volume after the heating season, resulting from the recession and, to a lesser extent, continued customer conservation. Lower volumes sold in the non-residential customer base accounted for more than 67% of the decline in propane sales volume. Additionally, included within the propane segment are revenues from wholesale and other propane activities of $6.9 million in the third quarter of fiscal 2009, which decreased $8.2 million compared to the prior year third quarter.

Revenues from the distribution of fuel oil and refined fuels of $23.1 million in the third quarter of fiscal 2009 decreased $32.2 million, or 58.2%, from $55.3 million in the prior year third quarter, primarily due to lower average selling prices and lower volumes. Average selling prices in our fuel oil and refined fuels segment in the third quarter of fiscal 2009 decreased 45.3% compared to the prior year third quarter due to lower product costs, thereby having a negative impact on revenues. Fuel oil and refined fuels gallons sold in the third quarter of fiscal 2009 decreased 2.9 million gallons, or 23.3%, to 9.7 million gallons from 12.6 million gallons in the prior year third quarter. Lower volumes in our fuel oil and refined fuels segment were attributable to the impact of ongoing customer conservation driven by adverse economic conditions.

Revenues in our natural gas and electricity segment decreased $10.4 million, or 46.0%, to $12.1 million in the third quarter of fiscal 2009 compared to $22.5 million in the prior year third quarter as a result of lower average selling prices and lower natural gas volumes. Revenues in our services segment decreased 9.4% to $8.3 million in the third quarter of fiscal 2009 from $9.2 million in the prior year third quarter primarily due to reduced installation activities as a result of the market decline in residential and commercial construction and other adverse economic conditions.

Cost of Products Sold

Given the retail nature of our operations, we maintain a certain level of priced physical inventory to ensure our field operations have adequate supply commensurate with the time of year. Our strategy has been, and will continue to be, to keep our physical inventory priced relatively close to market for our field operations. Consistent with past practices, we principally utilize futures and/or option contracts traded on the NYMEX to mitigate the price risk associated with our priced physical inventory. Under this risk management strategy, realized gains or losses on futures or option contracts will typically offset losses or gains on the physical inventory once the product is sold. We do not use futures or options contracts, or other derivative instruments, for speculative trading purposes.

With the unprecedented rise in commodity prices during the third quarter of fiscal 2008, we reported realized losses from our risk management activities which were not fully offset by sales of the physical product, resulting in a $14.5 million increase in cost of products sold during the third quarter of fiscal 2008.


	Three Months Ended									Percent
	June 27,			June 28,			(Decrease)			(Decrease)
(Dollars in thousands)	2009			2008			Increase			Increase
Cost of products sold
Propane	$	57,819		$	135,545		$	(77,726	)		(57.3	%)
Fuel oil and refined fuels		19,255			54,518			(35,263	)		(64.7	%)
Natural gas and electricity		7,859			19,780			(11,921	)		(60.3	%)
Services		1,696			2,437			(741	)		(30.4	%)
All other		834			694			140			20.2	%

Total cost of products sold	$	87,463		$	212,974		$	(125,511	)		(58.9	%)


As a percent of total revenues		47.4	%		69.7	%

The cost of products sold reported in the condensed consolidated statements of operations represents the weighted average unit cost of propane and fuel oil sold, 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 natural gas and electricity, as well as the cost of appliances and related parts sold or installed by our customer service centers computed on a basis that approximates the average cost of the products. Unrealized (non-cash) gains or losses from changes in the fair value of derivative instruments that are not designated as cash flow hedges are recorded in each quarterly reporting period within cost of products sold. Cost of products sold is reported exclusive of any depreciation and amortization; these amounts are reported separately within the condensed consolidated statements of operations.

Cost of products sold decreased $125.5 million, or 58.9%, to $87.5 million in the third quarter of fiscal 2009 compared to $213.0 million in the prior year third quarter due to the impact of the decline in product costs, lower volumes sold and realized losses from risk management activities of $14.5 million in the prior year third quarter, partially offset by the unfavorable impact of non-cash mark-to-market adjustments from our risk management activities in the third quarter of fiscal 2009 compared to the prior year third quarter. Cost of products sold in the third quarter of fiscal 2009 included a $6.1 million unrealized (non-cash) loss representing the net change in the fair value of derivative instruments during the period, compared to a $4.7 million unrealized (non-cash) gain in the prior year third quarter resulting in an increase of $10.8 million in cost of products sold in the third quarter of fiscal 2009 compared to the prior year third quarter ($2.9 million increase reported within the propane segment and $7.9 million increase reported within the fuel oil and refined fuels segment).

Cost of products sold associated with the distribution of propane and related activities of $57.8 million decreased $77.7 million, or 57.3%, compared to the prior year third quarter. Lower average propane costs and lower propane volumes resulted in a decrease of $54.6 million and $17.7 million, respectively, in cost of products sold during the third quarter of fiscal 2009 compared to the prior year third quarter. Cost of products sold from wholesale and other propane activities decreased $8.3 million compared to the prior year third quarter.

Cost of products sold associated with our fuel oil and refined fuels segment of $19.3 million decreased $35.3 million, or 64.7%, compared to the prior year third quarter. Lower average fuel oil costs and lower fuel oil volumes resulted in a decrease of $18.5 million and $10.2 million, respectively, in cost of products sold during the third quarter of fiscal 2009 compared to the prior year third quarter. In addition, the impact from risk management activities contributed to a decrease in cost of products sold compared to the prior year third quarter as a result of the $14.5 million realized loss, discussed above, reported in the fiscal 2008 third quarter.

Cost of products sold in our natural gas and electricity segment of $7.9 million decreased $11.9 million, or 60.3%, compared to the prior year third quarter due to lower product costs and lower natural gas volumes. Cost of products sold in our services segment of $1.7 million decreased $0.7 million, or 30.4%, compared to the prior year third quarter primarily due to lower sales volumes.

For the third quarter of fiscal 2009, total cost of products sold represented 47.4% of revenues compared to 69.7% in the prior year third quarter. This decrease was primarily attributable to the decrease in product costs which outpaced the decline in average selling prices, as well as the favorable impact from risk management activities.

Operating Expenses


	Three Months Ended
	June 27,			June 28,						Percent
(Dollars in thousands)	2009			2008			Decrease			Decrease
Operating expenses	$	72,295		$	76,455		$	(4,160	)		(5.4	%)
As a percent of total revenues		39.2	%		25.0	%

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

Operating expenses of $72.3 million in the third quarter of fiscal 2009 decreased $4.2 million, or 5.4%, compared to $76.5 million in the prior year third quarter as a result of lower fuel costs to operate our fleet and lower costs to operate our customer service centers, partially offset by higher variable compensation associated with higher earnings.

General and Administrative Expenses


	Three Months Ended
	June 27,			June 28,						Percent
(Dollars in thousands)	2009			2008			Decrease			Decrease
General and administrative expenses	$	13,108		$	13,268		$	(160	)		(1.2	%)
As a percent of total revenues		7.1	%		4.3	%

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

General and administrative expenses of $13.1 million for third quarter of fiscal 2009 was relatively flat compared to the prior year third quarter.

Depreciation and Amortization


	Three Months Ended
	June 27,			June 28,					Percent
(Dollars in thousands)	2009			2008			Increase		Increase
Depreciation and amortization	$	7,713		$	7,159		$	554		7.7	%
As a percent of total revenues		4.2	%		2.3	%

Depreciation and amortization expense of $7.7 million for the third quarter of fiscal 2009 increased approximately $0.5 million compared to $7.2 million in the prior year third quarter as a result of accelerating depreciation expense for certain assets retired in the third quarter of fiscal 2009.

Interest Expense, net


	Three Months Ended
	June 27,			June 28,					Percent
(Dollars in thousands)	2009			2008			Increase		Increase
Interest expense, net	$	10,068		$	9,524		$	544		5.7	%
As a percent of total revenues		5.5	%		3.1	%

Net interest expense of $10.1 million for the third quarter of fiscal 2009 increased approximately $0.6 million compared to $9.5 million in the prior year third quarter primarily due to lower interest income earned on invested cash and a non-cash charge of $0.4 million to write-off the unamortized debt issuance costs associated with the previous credit agreement which was terminated in the third quarter of fiscal 2009.

Net Loss and EBITDA

Net loss for the three months ended June 27, 2009, narrowed to $7.4 million, or $0.23 per Common Unit, compared to a net loss of $13.7 million, or $0.42 per Common Unit, in the prior year third quarter. EBITDA for the third quarter of fiscal 2009 amounted to $11.5 million, compared to $2.8 million in the prior year third quarter.

EBITDA represents income before deducting interest expense, income taxes, depreciation and amortization. Our management uses EBITDA as a measure of liquidity and we disclose it because we believe that it provides our investors and industry analysts with additional information to evaluate our ability to meet our debt service obligations and to pay our quarterly distributions to holders of our Common Units. In addition, certain of our incentive compensation plans covering executives and other employees utilize Adjusted EBITDA as the performance target. Moreover, our revolving credit agreement requires us to use Adjusted EBITDA as a component in calculating our leverage and interest coverage ratios. EBITDA and Adjusted EBITDA are not recognized terms under generally accepted accounting principles (“GAAP”) and should not be considered as an alternative to net income or net cash provided by operating activities determined in accordance with GAAP. Because EBITDA and Adjusted EBITDA as determined by us excludes some, but not all, items that affect net income, they may not be comparable to EBITDA and Adjusted EBITDA or similarly titled measures used by other companies.

The following table sets forth (i) our calculations of EBITDA and Adjusted EBITDA and (ii) a reconciliation of Adjusted EBITDA, as so calculated, to our net cash provided by operating activities:


	Three Months Ended
	June 27,			June 28,
(Dollars in thousands)	2009			2008
Net (loss)	$	(7,435	)	$	(13,747	)
Add:
Provision for (benefit from) income taxes		1,160			(157	)
Interest expense, net		10,068			9,524
Depreciation and amortization		7,713			7,159

EBITDA		11,506			2,779
Unrealized (non-cash) losses (gains) on changes in fair value of derivatives		6,148			(4,695	)

Adjusted EBITDA		17,654			(1,916	)
Add (subtract):
Provision for income taxes — current		(240	)		(87	)
Interest expense, net		(10,068	)		(9,524	)
Unrealized (non-cash) (losses) gains on changes in fair value of derivatives		(6,148	)		4,695
Compensation cost recognized under Restricted Unit Plan		644			817
Gain on disposal of property, plant and equipment, net		(147	)		(109	)
Changes in working capital and other assets and liabilities		62,851			54,725


Net cash provided by operating activities	$	64,546		$	48,601

Nine months Ended June 27, 2009 Compared to Nine months Ended June 28, 2008

In the commodities markets, prices for the first nine months of fiscal year 2009 trended in the opposite direction of the comparable period in the prior year, but with similar volatility. Overall, average posted prices for propane and fuel oil declined 52.9% and 46.0%, respectively, compared to the first nine months of the prior year. The decline in commodity prices contributed to a reduction in our product costs, which resulted in an increase in our retail propane and fuel oil unit margins for the first nine months of fiscal 2009 compared to the first nine months of the prior year.

Revenues


	Nine Months Ended
	June 27,		June 28,					Percent
(Dollars in thousands)	2009		2008		Decrease			Decrease
Revenues
Propane	$	750,392	$	946,700	$	(196,308	)		(20.7	%)
Fuel oil and refined fuels		142,420		247,609		(105,189	)		(42.5	%)
Natural gas and electricity		66,521		84,693		(18,172	)		(21.5	%)
Services		30,574		34,752		(4,178	)		(12.0	%)
All other		3,005		3,928		(923	)		(23.5	%)

Total revenues	$	992,912	$	1,317,682	$	(324,770	)		(24.6	%)

Total revenues decreased $324.8 million, or 24.6%, to $992.9 million for the nine months ended June 27, 2009 compared to $1,317.7 million for the nine months ended June 28, 2008 due to a combination of lower volumes and lower average selling prices associated with lower product costs. Volumes for the first nine months of fiscal 2009 were lower than the first nine months of the prior year due to the negative impact of adverse economic conditions, particularly on our commercial and industrial accounts, as well as ongoing customer conservation, partially offset by the favorable impact of colder temperatures. On an overall basis, temperatures in our service territories were slightly below normal levels during the first nine months of fiscal 2009 and 5% colder than the first nine months of the prior year.

Revenues from the distribution of propane and related activities of $750.4 million for the nine months ended June 27, 2009 decreased $196.3 million, or 20.7%, compared to $946.7 million for the nine months ended June 28, 2008, primarily due to lower average selling prices, as well as lower volumes in our commercial and industrial accounts and, to a lesser extent, our residential accounts. Average propane selling prices in the first nine months of fiscal 2009 decreased approximately 11.2% compared to the first nine months of the prior year due to lower product costs, thereby having a negative impact on revenues. Retail propane gallons sold in the first nine months of fiscal 2009 decreased 34.8 million gallons, or 10.6%, to 294.8 million gallons from 329.6 million gallons in the first nine months of the prior year. Additionally, included within the propane segment are revenues from wholesale and other propane activities of $31.6 million for the nine months ended June 27, 2009, which decreased $9.9 million compared to the nine months ended June 28, 2008.

Revenues from the distribution of fuel oil and refined fuels of $142.4 million for the nine months ended June 27, 2009 decreased $105.2 million, or 42.5%, from $247.6 million for the nine months ended June 28, 2008, primarily due to lower volumes and lower average selling prices. Fuel oil and refined fuels gallons sold in the first nine months of fiscal 2009 decreased 17.1 million gallons, or 25.3%, to 50.5 million gallons from 67.6 million gallons in the first nine months of the prior year. Lower volumes in our fuel oil and refined fuels segment were attributable to the impact of ongoing customer conservation driven by adverse economic conditions and continued high energy prices, combined with our decision to exit certain lower margin diesel and gasoline businesses. Our decision to exit the majority of our low sulfur diesel and gasoline businesses resulted in a reduction in volumes in the fuel oil and refined fuels segment of approximately 3.8 million gallons, or 21.9% of the total volume decline in the first nine months of fiscal 2009 compared to the first nine months of the prior year. Average selling prices in our fuel oil and refined fuels segment in the first nine months of fiscal 2009 decreased 23.9% compared to the first nine months of the prior year due to lower product costs, thereby having a negative impact on revenues.

Revenues in our natural gas and electricity segment decreased $18.2 million, or 21.5%, to $66.5 million for the nine months ended June 27, 2009 compared to $84.7 million for the nine months ended June 27, 2008 as a result of lower volumes. Revenues in our services segment decreased 12.0% to $30.6 million for the nine months ended June 27, 2009 from $34.8 million for the nine months ended June 28, 2008, primarily due to reduced installation activities as a result of the market decline in residential and commercial construction and other adverse economic conditions.

Cost of Products Sold


	Nine Months Ended
	June 27,			June 28,						Percent
(Dollars in thousands)	2009			2008			Decrease			Decrease
Cost of products sold
Propane	$	316,905		$	575,678		$	(258,773	)		(45.0	%)
Fuel oil and refined fuels		94,772			213,194			(118,422	)		(55.5	%)
Natural gas and electricity		49,707			71,271			(21,564	)		(30.3	%)
Services		7,070			9,614			(2,544	)		(26.5	%)
All other		1,498			1,689			(191	)		(11.3	%)

Total cost of products sold	$	469,952		$	871,446		$	(401,494	)		(46.1	%)


As a percent of total revenues		47.3	%		66.1	%

Cost of products sold decreased $401.5 million, or 46.1%, to $470.0 million for the nine months ended June 27, 2009 compared to $871.4 million for the nine months ended June 28, 2008 due to the impact of the decline in product costs, lower volumes sold and the favorable impact from our risk management activities. Cost of products sold in the first nine months of fiscal 2009 included a $0.8 million unrealized (non-cash) loss representing the net change in the fair value of derivative instruments during the period, compared to a $0.3 million unrealized (non-cash) loss in the first nine months of the prior year, resulting in a increase of $0.5 million in cost of products sold for the nine months ended June 27, 2009 compared to the nine months ended June 28, 2008 ($0.5 million decrease in cost of products sold reported within the propane segment and $1.0 million increase in cost of products sold within the fuel oil and refined fuels segment).

Cost of products sold associated with the distribution of propane and related activities of $316.9 million for the nine months ended June 27, 2009 decreased $258.8 million, or 45.0%, compared to the nine months ended June 28, 2008. Lower average propane costs and lower propane volumes resulted in a decrease of $173.4 million and $58.2 million, respectively, in cost of products sold during the first nine months of fiscal 2009 compared to the first nine months of the prior year. In addition, the impact from risk management activities during the first nine months of fiscal 2009 resulted in a $13.4 million decrease in cost of products sold compared to the first nine months of the prior year. Cost of products sold from wholesale and other propane activities decreased $13.3 million compared to the first nine months of the prior year due to lower product costs and sales volumes.

Cost of products sold associated with our fuel oil and refined fuels segment of $94.8 million for the nine months ended June 27, 2009 decreased $118.4 million, or 55.5%, compared to the nine months ended June 28, 2008. Lower average fuel oil costs and lower fuel oil volumes resulted in a decrease of $46.9 million and $48.3 million, respectively, in cost of products sold during the first nine months of fiscal 2009 compared to the first nine months of the prior year. In addition, the impact from risk management activities during the first nine months of fiscal 2009 resulted in a $24.2 million decrease in cost of products sold compared to the first nine months of the prior year. The favorable variance from risk management activities included the aforementioned $14.5 million in realized losses recognized in the third quarter of fiscal 2008.

Cost of products sold in our natural gas and electricity segment of $49.7 million for the nine months ended June 27, 2009 decreased $21.6 million, or 30.3%, compared to the nine months ended June 28, 2008 due to lower product costs and lower sales volumes. Cost of products sold in our services segment of $7.1 million for the first nine months of fiscal 2009 decreased $2.5 million, or 26.5%, compared to the first nine months of fiscal 2008 primarily due to lower sales volumes.

For the nine months ended June 27, 2009, total cost of products sold represented 47.3% of revenues compared to 66.1% for the nine months ended June 28, 2008. This decrease was primarily attributable to the decrease in product costs which outpaced the decline in average selling prices, as well as the positive effect of declining commodity prices on our risk management activities during the first nine months of fiscal 2009 compared to the negative effect of rising commodity prices on our risk management activities in the first nine months of the prior year.

Operating Expenses


	Nine Months Ended
	June 27,			June 28,					Percent
(Dollars in thousands)	2009			2008			Increase		Increase
Operating expenses	$	236,206		$	235,495		$	711		0.3	%
As a percent of total revenues		23.8	%		17.9	%

Operating expenses of $236.2 million for the nine months ended June 27, 2009 were relatively flat compared to the nine months ended June 28, 2008 as higher variable compensation expense associated with higher earnings was entirely offset by our continued efforts to drive operational efficiencies and reduce costs across all operating segments. Savings were primarily attributable to payroll and benefit related expenses as a result of lower headcount, lower fuel costs to operate our fleet and lower bad debt expense.

General and Administrative Expenses


	Nine Months Ended
	June 27,			June 28,					Percent
(Dollars in thousands)	2009			2008			Increase		Increase
General and administrative expenses	$	45,671		$	37,632		$	8,039		21.4	%
As a percent of total revenues		4.6	%		2.9	%

General and administrative expenses of $45.7 million for the nine months ended June 27, 2009 increased approximately $8.1 million compared to $37.6 million during the nine months ended June 28, 2008. The increase was primarily attributable to higher variable compensation expense resulting from higher earnings in the first nine months of fiscal 2009 compared to the first nine months of the prior year and higher compensation expense recognized under certain long-term incentive plans.

Depreciation and Amortization


	Nine Months Ended
	June 27,			June 28,					Percent
(Dollars in thousands)	2009			2008			Increase		Increase
Depreciation and amortization	$	21,867		$	21,325		$	542		2.5	%
As a percent of total revenues		2.2	%		1.6	%

Depreciation and amortization expense of $21.9 million for the nine months ended June 27, 2009 increased $0.5 million, or 2.5%, compared to $21.3 million during the nine months ended June 28, 2008 as a result of accelerating depreciation expense for certain assets retired in the third quarter of fiscal 2009.

Interest Expense, net


	Nine Months Ended
	June 27,			June 28,					Percent
(Dollars in thousands)	2009			2008			Increase		Increase
Interest expense, net	$	28,913		$	27,330		$	1,583		5.8	%
As a percent of total revenues		2.9	%		2.1	%

Net interest expense of $28.9 million for the nine months ended June 27, 2009 increased $1.6 million, or 5.8%, compared to $27.3 million for the nine months ended June 28, 2008 as a result of lower market interest rates for short-term investments, which contributed to less interest income earned, and a non-cash charge of $0.4 million to write-off the unamortized debt issuance costs associated with the previous credit agreement which was terminated in the third quarter of fiscal 2009.

Discontinued Operations

On October 2, 2007, we completed the sale of our Tirzah, South Carolina underground granite propane storage cavern, and associated 62-mile pipeline, for approximately $53.7 million in cash, after taking into account certain adjustments. As a result of this sale, we reported a $43.7 million gain on disposal of discontinued operations in the first nine months of fiscal 2008.

Net Income and EBITDA

Net income for the nine months ended June 27, 2009 amounted to $188.1 million, or $5.73 per Common Unit, an increase of $21.9 million, or $0.65 per Common Unit, compared to $166.2 million, or $5.08 per Common Unit for the first nine months of the prior year. EBITDA amounted to $241.1 million for the nine months ended June 27, 2009 compared to $216.8 million for the first nine months of the prior year.

The following table sets forth (i) our calculations of EBITDA and Adjusted EBITDA and (ii) a reconciliation of Adjusted EBITDA, as so calculated, to our net cash provided by operating activities:


	Nine Months Ended
	June 27,			June 28,
(Dollars in thousands)	2009			2008

Net income	$	188,119		$	166,205
Add:
Provision for income taxes		2,184			1,956
Interest expense, net		28,913			27,330
Depreciation and amortization		21,867			21,325

EBITDA		241,083			216,816
Unrealized (non-cash) losses on changes in fair value of derivatives		832			323

Adjusted EBITDA		241,915			217,139
Add (subtract):
Provision for income taxes — current		(804	)		(679	)
Interest expense, net		(28,913	)		(27,330	)
Unrealized (non-cash) losses on changes in fair value of derivatives		(832	)		(323	)
Compensation cost recognized under Restricted Unit Plan		1,885			1,503
Gain on disposal of property, plant and equipment, net		(770	)		(1,821	)
Gain on disposal of discontinued operations		—			(43,707	)
Changes in working capital and other assets and liabilities		11,017			(87,794	)


Net cash provided by operating activities	$	223,498		$	56,988

Liquidity and Capital Resources

Analysis of Cash Flows

Operating Activities. Due to the seasonal nature of the propane and fuel oil businesses, cash flows generated from operating activities are typically greater during the winter and spring seasons (our second and third fiscal quarters) as customers pay for products purchased during the heating season. For the nine months ended June 27, 2009, net cash provided by operating activities was $223.5 million, representing an increase of $166.5 million compared to net cash provided by operating activities of $57.0 million for the first nine months of the prior year. This improvement was primarily attributable to higher earnings from continuing operations, coupled with the decline in propane and fuel oil commodity prices that resulted in a smaller investment in working capital in the first nine months of fiscal 2009 compared to the first nine months of the prior year. We continued to fund working capital through operating cash flow without the need to access the revolving credit facility.

Investing Activities. Net cash used in investing activities of $9.9 million for the nine months ended June 27, 2009 consisted of capital expenditures of $13.8 million (including $6.4 million for maintenance expenditures and $7.4 million to support the growth of operations), partially offset by $3.9 million in net proceeds from the sale of property, plant and equipment. Net cash provided by investing activities of $39.9 million for the nine months ended June 28, 2008 consisted of the net proceeds from the sale of discontinued operations of $53.7 million and the net proceeds from the sale of property, plant and equipment of $3.5 million, partially offset by capital expenditures of $17.3 million (including $8.6 million for maintenance expenditures and $8.7 million to support the growth of operations).

Financing Activities. Net cash used in financing activities for the nine months ended June 27, 2009 of $95.2 million reflects quarterly distributions to Common Unitholders at a rate of $0.815 per Common Unit paid in respect of the second quarter of fiscal 2009, $0.81 per Common Unit paid in respect of the first quarter of fiscal 2009 and $0.805 per Common Unit paid in respect of the fourth quarter of fiscal 2008, as well as repayment of $110.0 million under our term loan and payment of debt issuance costs associated with the revolving credit facility executed on June 26, 2009, partially offset by proceeds from long-term borrowings under the new revolving credit facility. Net cash used in financing activities for the nine months ended June 28, 2008 of $74.9 million reflects quarterly distributions to Common Unitholders at a rate of $0.775 per Common Unit paid in respect of the second quarter of fiscal 2008, $0.7625 per Common Unit paid in respect of the first quarter of fiscal 2008 and $0.75 per Common Unit paid in respect of the fourth quarter of fiscal 2007.

Summary of Long-Term Debt Obligations and Revolving Credit Lines

Our long-term borrowings and revolving credit lines consist of $425.0 million in 6.875% senior notes due December 2013 (the “2003 Senior Notes”) and a $250.0 million senior secured revolving credit facility at the Operating Partnership level (the “Revolving Credit Facility”). The Revolving Credit Facility was executed on June 26, 2009 and replaces the Operating Partnership’s previous credit facility which, as amended, provided for a $108.0 million term loan (the “Term Loan”) and a separate $175.0 million working capital facility both of which were scheduled to mature in March 2010. Borrowings under the Revolving Credit Facility may be used for general corporate purposes, including working capital, capital expenditures and acquisitions until maturity on June 25, 2013. Our Operating Partnership has the right to prepay loans under the Revolving Credit Facility, in whole or in part, without penalty at any time prior to maturity. At closing, the Operating Partnership borrowed $100.0 million under the Revolving Credit Facility and, with cash on hand, repaid the $108.0 million then outstanding under the Term Loan and terminated the previous credit agreement. We have standby letters of credit issued under the Revolving Credit Facility in the aggregate amount of $57.2 million primarily in support of retention levels under our self-insurance programs, which expire periodically through October 25, 2010. Therefore, as of June 27, 2009 we had available borrowing capacity of $92.8 million under the Revolving Credit Facility.

The 2003 Senior Notes mature on December 15, 2013 and require semi-annual interest payments. We are permitted to redeem some or all of the 2003 Senior Notes any time on or after December 15, 2008 at redemption prices specified in the indenture governing the 2003 Senior Notes. In addition, the 2003 Senior Notes have a change of control provision that would require us to offer to repurchase the notes at 101% of the principal amount repurchased, if the holders of the notes elected to exercise the right of repurchase. Borrowings under the Revolving Credit Facility bear interest at prevailing interest rates based upon, at our Operating Partnership’s option, LIBOR plus the applicable margin or the base rate, defined as the higher of the Federal Funds Rate plus ¹/2 of 1%, the agent bank’s prime rate, or LIBOR plus 1%, plus in each case the applicable margin. The applicable margin is dependent upon our ratio of total debt to EBITDA on a consolidated basis, as defined in the Revolving Credit Facility. As of June 27, 2009, the interest rate for the Revolving Credit Facility was approximately 4.1% and will be reset at the end of each calendar quarter.

In connection with the Revolving Credit Facility, our Operating Partnership amended its existing interest rate swap agreement, which has a termination date of March 31, 2010, to reduce the notional amount to $100.0 million from $108.0 million. Our Operating Partnership will pay a fixed interest rate of 4.66% to the issuing lender on notional principal amount outstanding, 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 Revolving Credit Facility 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. The Revolving Credit Facility contains certain financial covenants (a) requiring the consolidated interest coverage ratio, as defined, at the Partnership level to be not less than 2.5 to 1.0 as of the end of any fiscal quarter; (b) prohibiting the total consolidated leverage ratio, as defined, at the Partnership level from being greater than 4.5 to 1.0 as of the end of any fiscal quarter; and (c) prohibiting the senior secured consolidated leverage ratio, as defined, of the Operating Partnership from being greater than 3.0 to 1.0 as of the end of any fiscal quarter. Under the 2003 Senior Note indenture, we are generally permitted to make cash distributions equal to available cash, as defined, as of the end of the immediately preceding quarter, if no event of default exists or would exist upon making such distributions, and the Partnership’s consolidated fixed charge coverage ratio, as defined, is greater than 1.75 to 1. We were in compliance with all covenants and terms of the 2003 Senior Notes and the Revolving Credit Facility as of June 27, 2009.

Partnership Distributions

We are required to make distributions in an amount equal to all of our Available Cash, as defined in the Third Amended and Restated Partnership Agreement (the “Partnership Agreement”), as amended, no more than 45 days after the end of each fiscal quarter to holders of record on the applicable record dates. Available Cash, as defined in the Partnership Agreement, generally means all cash on hand at the end of the respective fiscal quarter less the amount of cash reserves established by the Board of Supervisors in its reasonable discretion for future cash requirements. These reserves are retained for the proper conduct of our business, the payment of debt principal and interest and for distributions during the next four quarters. The Board of Supervisors reviews the level of Available Cash on a quarterly basis based upon information provided by management.

On July 23, 2009, we announced a quarterly distribution of $0.825 per Common Unit, or $3.30 on an annualized basis, in respect of the third quarter of fiscal 2009 payable on August 11, 2009 to holders of record on August 4, 2009. The annualized distribution represents an increase of $0.04 per Common Unit from the previous distribution rate, representing the twenty-second increase since our recapitalization in 1999 and a growth rate of 3.1% in the quarterly distribution rate compared to the third quarter of fiscal 2008.

Other Commitments

We have a noncontributory, cash balance format, defined benefit pension plan which was frozen to new participants effective January 1, 2000. Effective January 1, 2003, the defined benefit pension plan was amended such that future service credits ceased and eligible employees would receive interest credits only toward their ultimate retirement benefit. At June 27, 2009, the fair value of the plan assets approximated the accumulated benefit obligation of the plan. We also provide postretirement health care and life insurance benefits for certain retired employees under a plan that was also frozen to new participants effective January 1, 2000. At June 27, 2009, we had a liability for accrued retiree health and life benefits of $18.8 million.

We are self-insured for general and product, workers’ compensation and automobile liabilities up to predetermined thresholds above which third party insurance applies. At June 27, 2009, we had accrued insurance liabilities of $52.7 million, and an insurance recovery asset of $16.1 million related to the amount of the liability expected to be covered by insurance carriers.

Off-Balance Sheet Arrangements

Guarantees

We have residual value guarantees associated with certain of our operating leases, related primarily to transportation equipment, with remaining lease periods scheduled to expire periodically through fiscal 2016. 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 $18.3 million as of June 27, 2009. The fair value of residual value guarantees for outstanding operating leases was de minimis as of June 27, 2009 and September 27, 2008.

Recently Issued Accounting Standards

In December 2008, the FASB issued an FSP on Statement 132(R)-1, “Employers’ Disclosure about Postretirement Benefit Plan Assets” (“FSP 132(R)-1”), which amends SFAS No. 132(R) to require more detailed disclosures about employers’ pension plan assets. These new disclosures will include more information on investment strategies, major categories of plan assets, concentrations of risk within plan assets and valuation techniques used to measure the fair value of plan assets. FSP 132(R)-1 is effective for fiscal years ending after December 15, 2009, which will be our 2010 fiscal year ending September 25, 2010. Since FSP 132(R)-1 only addresses disclosure requirements, the adoption of FSP 132(R)-1 is not expect to have an impact on our consolidated financial position, results of operations and cash flows.

Also in December 2007, the FASB issued a revised SFAS No. 141 “Business Combinations” (“SFAS 141R”). Among other things, SFAS 141R requires an entity to recognize acquired assets, liabilities assumed and any noncontrolling interest at their respective fair values as of the acquisition date, clarifies how goodwill involved in a business combination is to be recognized and measured, as well as requires the expensing of acquisition-related costs as incurred. SFAS 141R is effective for business combinations entered into in fiscal years beginning on or after December 15, 2008, which will be our 2010 fiscal year beginning September 27, 2009, with early adoption prohibited.


ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

We enter into product supply contracts that are generally one-year agreements subject to annual renewal, and also purchase product on the open market. Our propane supply contracts typically provide for pricing based upon index formulas using the posted prices established at major supply points such as Mont Belvieu, Texas, or Conway, Kansas (plus transportation costs) at the time of delivery. In addition, to supplement our annual purchase requirements, we may utilize forward fixed price purchase contracts to acquire a portion of the propane that we resell to our customers, which allows us to manage our exposure to unfavorable changes in commodity prices and to ensure adequate physical supply. The percentage of contract purchases, and the amount of supply contracted for under forward contracts at fixed prices, will vary from year to year based on market conditions. In certain instances, and when market conditions are favorable, we are able to purchase product under our supply arrangements at a discount to the market.

Product cost changes can occur rapidly over a short period of time and can impact profitability. We attempt to reduce commodity price risk by pricing product on a short-term basis. The level of priced, physical product maintained in storage facilities and at our customer service centers for immediate sale to our customers will vary depending on several factors, including, but not limited to, price, availability of supply, and demand for a given time of the year. Typically, our on hand priced position does not exceed more than four to eight weeks of our supply needs, depending on the time of the year. In the course of normal operations, we routinely enter into contracts such as forward priced physical contracts for the purchase or sale of propane and fuel oil that, under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended (“SFAS 133”), qualify for and are designated as normal purchase or normal sale contracts. Such contracts are exempted from the fair value accounting requirements of SFAS 133 and are accounted for at the time product is purchased or sold under the related contract.

Under our hedging and risk management strategies, we enter into a combination of exchange-traded futures and option contracts, forward contracts and, in certain instances, over-the-counter options (collectively, “derivative instruments”) to manage the price risk associated with priced, physical product and with future purchases of the commodities used in our operations, principally propane and fuel oil, as well as to ensure the availability of product during periods of high demand. We do not use derivative instruments for speculative or trading purposes. Futures and forward contracts require that we sell or acquire propane or fuel oil at a fixed price for delivery at fixed future dates. An option contract allows, but does not require, its holder to buy or sell propane or fuel oil at a specified price during a specified time period. However, the writer of an option contract must fulfill the obligation of the option contract, should the holder choose to exercise the option. At expiration, the contracts are settled by the delivery of the product to the respective party or are settled by the payment of a net amount equal to the difference between the then current price and the fixed contract price or options exercise price. To the extent that we utilize derivative instruments to manage exposure to commodity price risk and commodity prices move adversely in relation to the contracts, we could suffer losses on those derivative instruments when settled. Conversely, if prices move favorably, we could realize gains. Under our hedging and risk management strategy, realized gains or losses on derivative instruments will typically offset losses or gains on the physical inventory once the product is sold to customers at market prices.

Market Risk

We are subject to commodity price risk to the extent that propane or fuel oil market prices deviate from fixed contract settlement amounts. Futures traded with brokers of the NYMEX require daily cash settlements in margin accounts. Forward and option contracts are generally settled at the expiration of the contract term either by physical delivery or through a net settlement mechanism. Market risks associated with 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 over-the-counter, forward and propane option contracts to the extent the counterparties do not perform. We evaluate the financial condition of each counterparty with which we conduct business and establish credit limits to reduce exposure to the risk of non-performance by our counterparties.

Interest Rate Risk

A portion of our borrowings bear interest at prevailing interest rates based upon, at the Operating Partnership’s option, LIBOR, plus an applicable margin or the base rate, defined as the higher of the Federal Funds Rate plus ¹/2 of 1% or the agent bank’s prime rate, or LIBOR plus 1%, plus the applicable margin. The applicable margin is dependent on the level of the Partnership’s 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 June 26, 2009, we amended our interest rate swap contract in conjunction with the execution of the Revolving Credit Facility to reduce the notional amount from $108 million to $100 million. The interest rate swap, which has a termination date of March 31, 2010, is being accounted for under SFAS 133 and has been designated as a cash flow hedge. Changes in the fair value of the interest rate swap are recognized in other comprehensive income (“OCI”) until the hedged item is recognized in earnings. At June 27, 2009, the fair value of the interest rate swap was $3.0 million representing an unrealized loss and is included within other liabilities with a corresponding debit in OCI.

Derivative Instruments and Hedging Activities

Pursuant to SFAS 133, all of our derivative instruments are reported on the balance sheet at their fair values. On the date that futures, forward and option contracts are entered into, we make a determination as to whether the derivative instrument qualifies for designation as a hedge. Changes in the fair value of derivative instruments are recorded each period in current period earnings or OCI, depending on whether a derivative instrument is designated as a hedge and, if so, the type of hedge. For derivative instruments designated as cash flow hedges, we formally assess, both at the hedge contract’s inception and on an ongoing basis, whether the hedge contract is highly effective in offsetting changes in cash flows of hedged items. Changes in the fair value of derivative instruments designated as cash flow hedges are reported in OCI to the extent effective and reclassified into cost of products sold during the same period in which the hedged item affects earnings. The mark-to-market gains or losses on ineffective portions of cash flow hedges are immediately recognized in cost of products sold. Changes in the fair value of derivative instruments that are not designated as cash flow hedges, and that do not meet the normal purchase and normal sale exemption under SFAS 133, are recorded within cost of products sold as they occur. Cash flows associated with derivative instruments are reported as operating activities within the condensed consolidated statement of cash flows.

At June 27, 2009, the fair value of derivative instruments described above resulted in current derivative assets (unrealized gains) of $6.5 million included within other current assets, non-current derivative assets of $0.5 million included within other assets, $5.0 million of derivative liabilities (unrealized losses) included within other current liabilities and non-current derivative liabilities of $0.3 million included within other liabilities. Cost of products sold included unrealized (non-cash) losses of $6.1 million and $0.8 million for the three and nine months ended June 27, 2009, respectively, and unrealized (non-cash) (gains) losses of $(4.7) million and $0.3 million for the three and nine months ended June 28, 2008, respectively, attributable to the change in fair value of derivative instruments not designated as cash flow hedges.

Sensitivity Analysis

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

The fair value of open positions as of June 27, 2009 for each of the future periods.

The estimated forward market prices as of June 27, 2009 as derived from the NYMEX for traded commodities for each of the future periods.

The market prices determined in B. above were adjusted adversely by a hypothetical 10% change in the forward prices and compared to the fair value 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, a hypothetical 10% adverse change in market prices for which a futures, forward and/or option contract exists indicates potential future losses in future earnings of $4.7 million as of June 27, 2009. See also Item 7A of our Annual Report on Form 10-K for the fiscal year ended September 27, 2008. 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.

ITEM 4. CONTROLS AND PROCEDURES

(a) The Partnership maintains disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934) that are designed to provide reasonable assurance that information required to be disclosed in the Partnership’s filings and submissions under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the periods specified in the rules and forms of the SEC and that such information is accumulated and communicated to the Partnership’s management, including its principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

The Partnership completed an evaluation under the supervision and with participation of the Partnership’s management, including the Partnership’s principal executive officer and principal financial officer, of the effectiveness of the design and operation of the Partnership’s disclosure controls and procedures as of June 27, 2009. Based on this evaluation, the Partnership’s principal executive officer and principal financial officer have concluded that as of June 27, 2009, such disclosure controls and procedures were effective to provide the reasonable assurance described above.

(b) There have not been any changes in the Partnership’s internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934) during the quarter ended June 27, 2009 that have materially affected or are reasonably likely to materially affect its internal control over financial reporting.

ITEM 1A. RISK FACTORS

The following are additional risk factors to those previously disclosed in the Partnership’s Form 10-K for the fiscal year ended September 27, 2008.

The adoption of Climate Change legislation by Congress could result in increased operating costs and reduced demand for the products and services we provide.

On June 26, 2009, the U.S. House of Representatives approved adoption of the “American Clean Energy and Security Act of 2009,” also known as the “Waxman-Markey cap-and-trade legislation” or “ACESA.” The purpose of ACESA is to control and reduce emissions of “greenhouse gases” (“GHGs”) in the United States. GHGs are certain gases, including carbon dioxide and methane, that may contribute to the warming of the Earth’s atmosphere and other climatic changes. ACESA would establish an economy-wide cap on emissions of GHGs in the United States and would require certain regulated entities to obtain GHG emission “allowances” corresponding to the annual emission of GHGs attributable to their products or operations. Regulated entities under ACESA include producers of natural gas liquids (“NGLs”), local natural gas distribution companies, and certain industrial facilities. Under ACESA, the number of authorized emission allowances would decline each year, resulting in an expected and progressive increase in the cost or value of the allowances. The net effect of maintaining emission allowances under ACESA would be to increase the costs associated with the combusting of carbon-based fuels such as natural gas, NGLs (including propane), and refined petroleum products.

The U.S. Senate has begun work on its own legislation for controlling and reducing domestic GHG emissions, and President Obama has indicated his support of legislation to reduce GHG emissions through an emission allowance system. Although it is not possible at this time to predict if or when the Senate may act on climate change legislation or how any Senate bill would be reconciled with ACESA, any adopted laws or regulations that restrict or reduce GHG emissions could require us to incur increased operating costs and could adversely affect demand for the products and services we provide.

The adoption of derivatives legislation by Congress could have an adverse impact on our ability to hedge risks associated with our business.

Congress is currently considering legislation to impose restrictions on certain transactions involving derivatives, which could affect the use of derivatives in hedging transactions. ACESA contains provisions that would prohibit private energy commodity derivative and hedging transactions. ACESA would expand the power of the Commodity Futures Trading Commission (“CFTC”), to regulate derivative transactions related to energy commodities, including oil and natural gas, and to mandate clearance of such derivative contracts through registered derivative clearing organizations. Under ACESA, the CFTC’s expanded authority over energy derivatives would terminate upon the adoption of general legislation covering derivative regulatory reform. The Chairman of the CFTC has announced that the CFTC intends to conduct hearings to determine whether to set limits on trading and positions in commodities with finite supply, particularly energy commodities, such as crude oil, natural gas and other energy products. The CFTC also is evaluating whether position limits should be applied consistently across all markets and participants. In addition, the Treasury Department recently has indicated that it intends to propose legislation to subject all OTC derivative dealers and all other major OTC derivative market participants to substantial supervision and regulation, including by imposing conservative capital and margin requirements and strong business conduct standards. Derivative contracts that are not cleared through central clearinghouses and exchanges may be subject to substantially higher capital and margin requirements. Although it is not possible at this time to predict whether or when Congress may act on derivatives legislation or how any climate change bill approved by the Senate would be reconciled with ACESA, any laws or regulations that may be adopted that subject us to additional capital or margin requirements relating to, or to additional restrictions on, our trading and commodity positions could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activity.

PART II

ITEM 6. EXHIBITS

(a) Exhibits


	3.1			Third Amended and Restated Agreement of Limited Partnership of the Operating Partnership dated as of June 24, 2009. (Incorporated by reference to Exhibit 10.2 to the Partnership’s Current Report on Form 8-K filed on June 30, 2009).

	3.2			Amended and Restated Certificate of Limited Partnership of Suburban Propane Partners, L.P. dated May 26, 1999 (filed herewith).

	3.3			Amended and Restated Certificate of Limited Partnership of Suburban Partners, L.P. dated May 26, 1999 (filed herewith).

	10.1			Agreement between Mark A. Alexander and Suburban Propane Partners, L.P., dated April 22, 2009 (corrected version filed herewith).

	10.2			Credit Agreement dated June 26, 2009. (Incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed on June 30, 2009).

	10.4			Suburban Propane Partners, L.P. 2009 Restricted Unit Plan, effective August 1, 2009. (Incorporated by reference to Exhibit 99.1 to the Partnership’s Registration Statement on Form S-8 filed on July 24, 2009).

	31.1			Certification of the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. (Filed herewith).

	31.2			Certification of the Chief Financial Officer and Chief Accounting Officer 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 Chief Financial Officer and Chief Accounting Officer Pursuant to 18 U.S.C. Section 1350 as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (Filed herewith).

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


	SUBURBAN PROPANE PARTNERS, L.P.
August 6, 2009	By:	/s/ MICHAEL A. STIVALA
Date		Michael A. Stivala
		Chief Financial Officer and Chief Accounting Officer

August 6, 2009	By:	/s/ MICHAEL A. KUGLIN
Date		Michael A. Kuglin
		Controller

EXHIBIT INDEX


Exhibit
Number		Description

	3.2	Amended and Restated Certificate of Limited Partnership of Suburban Propane Partners, L.P. dated May 26, 1999 (filed herewith).

	3.3	Amended and Restated Certificate of Limited Partnership of Suburban Partners, L.P. dated May 26, 1999 (filed herewith).

	10.1	Agreement between Mark A. Alexander and Suburban Propane Partners, L.P., dated April 22, 2009 (corrected version filed herewith).

	31.1	Certification of the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. (Filed herewith).

	31.2	Certification of the Chief Financial Officer and Chief Accounting Officer 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 Chief Financial Officer and Chief Accounting Officer Pursuant to 18 U.S.C. Section 1350 as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (Filed herewith).