Edgar Filing: STAR GAS PARTNERS LP

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FORM 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

(Mark One)

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended December 31, 2011

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number: 001-14129

STAR GAS PARTNERS, L.P.

(Exact name of registrants as specified in its charters)


Delaware		06-1437793
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

2187 Atlantic Street, Stamford, Connecticut		06902
(Address of principal executive office)

(203) 328-7310

(Registrant’s telephone number, including area code)

(Former name, former address and former fiscal year, if changed since last report)

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 x No ¨

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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

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

Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Act). Yes ¨ No x

At January 31, 2012, the registrant had 61,301,777 common units outstanding.

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

INDEX TO FORM 10-Q


	Page

Part I Financial Information

Item 1—Condensed Consolidated Financial Statements

Condensed Consolidated Balance Sheets as of December 31, 2011 (unaudited) and September 30, 2011		3

Condensed Consolidated Statements of Operations (unaudited) for the three months ended December 31, 2011 and December 31, 2010		4

Condensed Consolidated Statement of Partners’ Capital and Comprehensive Income for the three months ended December 31, 2011 (unaudited)		5

Condensed Consolidated Statements of Cash Flows (unaudited) for the three months ended December 31, 2011 and December 31, 2010		6

Notes to Condensed Consolidated Financial Statements (unaudited)		7-19

Item 2—Management’s Discussion and Analysis of Financial Condition and Results of Operations		20-35

Item 3—Quantitative and Qualitative Disclosures About Market Risk		36

Item 4—Controls and Procedures		36

Part II Other Information:

Item 1—Legal Proceedings		37

Item 1A—Risk Factors		37

Item 2— Unregistered Sales of Equity Securities and Use of Proceeds		38

Item 6—Exhibits		39

Signatures		40

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS


(in thousands)	December 31, 2011			September 30, 2011
	(unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	13,920		$	86,789
Receivables, net of allowance of $9,749 and $9,530 respectively		177,676			92,967
Inventories		100,505			80,536
Fair asset value of derivative instruments		—			3,674
Current deferred tax asset, net		12,625			13,155
Prepaid expenses and other current assets		26,792			22,296

Total current assets		331,518			299,417


Property and equipment, net		52,296			47,131
Goodwill		205,466			199,296
Intangibles, net		60,570			52,348
Long-term deferred tax asset, net		16,741			17,646
Deferred charges and other assets, net		10,585			10,291

Total assets	$	677,176		$	626,129


LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Accounts payable	$	25,776		$	18,569
Revolving credit facility borrowings		46,834			—
Fair liability value of derivative instruments		8,122			3,322
Accrued expenses and other current liabilities		75,821			76,428
Unearned service contract revenue		49,895			40,903
Customer credit balances		66,345			67,214

Total current liabilities		272,793			206,436


Long-term debt		124,286			124,263
Other long-term liabilities		21,840			22,797

Partners’ capital
Common unitholders		285,173			299,913
General partner		144			187
Accumulated other comprehensive loss, net of taxes		(27,060	)		(27,467	)

Total partners’ capital		258,257			272,633

Total liabilities and partners’ capital	$	677,176		$	626,129

See accompanying notes to condensed consolidated financial statements.

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS


	Three Months Ended December 31,
(in thousands, except per unit data - unaudited)	2011			2010

Sales:
Product	$	406,669		$	404,968
Installations and service		54,805			54,533

Total sales		461,474			459,501
Cost and expenses:
Cost of product		316,673			301,672
Cost of installations and service		52,351			52,622
(Increase) decrease in the fair value of derivative instruments		7,118			(13,906	)
Delivery and branch expenses		67,757			65,961
Depreciation and amortization expenses		3,629			4,577
General and administrative expenses		5,365			4,924

Operating income		8,581			43,651
Interest expense		(3,452	)		(4,220	)
Interest income		728			532
Amortization of debt issuance costs		(274	)		(694	)
Loss on redemption of debt		—			(1,700	)

Income before income taxes		5,583			37,569
Income tax expense		2,652			17,011

Net income	$	2,931		$	20,558

General Partner’s interest in net income		15			99

Limited Partners’ interest in net income	$	2,916		$	20,459




Basic and Diluted income per Limited Partner Unit (1)	$	0.05		$	0.26


Weighted average number of Limited Partner units outstanding:
Basic and Diluted		64,189			67,078

(1)	See Note 3 Summary of Significant Accounting Policies - Net Income per Limited Partner Unit.

See accompanying notes to condensed consolidated financial statements.

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

AND COMPREHENSIVE INCOME


	Number of Units
(in thousands)	Common			General Partner		Common			General Partner			Accum. Other Comprehensive Income (Loss)			Total Partners’ Capital
Balance as of September 30, 2011		64,970			326	$	299,913		$	187		$	(27,467	)	$	272,633

Comprehensive income (unaudited):
Net income							2,916			15			—			2,931
Unrealized gain on pension plan obligation		—			—		—			—			688			688
Tax effect of unrealized gain on pension plan		—			—		—			—			(281	)		(281	)

Total comprehensive income		—			—		2,916			15			407			3,338
Distributions		—			—		(5,014	)		(58	)		—			(5,072	)
Retirement of units (1)		(2,448	)		—		(12,642	)		—			—			(12,642	)

Balance as of December 31, 2011 (unaudited)		62,522			326	$	285,173		$	144		$	(27,060	)	$	258,257

(1)	See Note 2 - Common Unit Repurchase and Retirement.

See accompanying notes to condensed consolidated financial statements.

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


	Three Months Ended December 31,
(in thousands - unaudited)	2011			2010

Cash flows provided by (used in) operating activities:
Net income	$	2,931		$	20,558

Adjustment to reconcile net income to net cash provided by (used in) operating activities:
(Increase) decrease in fair value of derivative instruments		7,118			(13,906	)
Depreciation and amortization		3,903			5,271
Loss on redemption of debt		—			1,700
Provision for losses on accounts receivable		1,450			2,648
Change in deferred taxes		1,154			14,980
Changes in operating assets and liabilities:
Increase in receivables		(79,111	)		(115,161	)
Increase in inventories		(18,883	)		(10,324	)
Increase in other assets		(3,202	)		(7,358	)
Increase in accounts payable		7,205			16,781
Decrease in customer credit balances		(5,316	)		(23,134	)
Increase in other current and long-term liabilities		7,986			19,235

Net cash used in operating activities		(74,765	)		(88,710	)


Cash flows provided by (used in) investing activities:
Capital expenditures		(1,276	)		(1,558	)
Proceeds from sales of fixed assets		241			14
Acquisitions		(25,863	)		(1,638	)

Net cash used in investing activities		(26,898	)		(3,182	)


Cash flows provided by (used in) financing activities:
Revolving credit facility borrowings		46,834			13,076
Repayment of debt		—			(82,499	)
Proceeds from the issuance of debt		—			124,188
Debt extinguishment costs		—			(1,409	)
Distributions		(5,072	)		(4,905	)
Unit repurchase		(12,642	)		—
Deferred charges		(326	)		(3,817	)

Net cash provided by financing activities		28,794			44,634


Net decrease in cash and cash equivalents		(72,869	)		(47,258	)

Cash and cash equivalents at beginning of period		86,789			61,062

Cash and cash equivalents at end of period	$	13,920		$	13,804

See accompanying notes to condensed consolidated financial statements.

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

1) Partnership Organization

Star Gas Partners, L.P. (“Star Gas Partners,” the “Partnership,” “we,” “us,” or “our”) is a home heating oil and propane distributor and services provider with one reportable operating segment that principally provides services to residential and commercial customers to heat their homes and buildings. Star Gas Partners is a master limited partnership, which at December 31, 2011, had outstanding 62.5 million common units (NYSE: “SGU”), representing the 99.5% limited partner interest in Star Gas Partners, and 0.3 million general partner units, representing the 0.5% general partner interest in Star Gas Partners.

The Partnership is organized as follows:

•

The general partner of the Partnership is Kestrel Heat, LLC, a Delaware limited liability company (“Kestrel Heat” or the “general partner”). The Board of Directors of Kestrel Heat is appointed by its sole member, Kestrel Energy Partners, LLC, a Delaware limited liability company (“Kestrel”).

•

The Partnership’s operations are conducted through Petro Holdings, Inc. and its subsidiaries (“Petro”). Petro is a Minnesota corporation that is an indirect wholly-owned subsidiary of the Partnership. Petro is subject to Federal and state corporation income taxes. Petro is a Northeast and Mid-Atlantic region retail distributor of home heating oil and propane that at December 31, 2011 served approximately 417,000 full-service residential and commercial home heating oil and propane customers. Petro also sold home heating oil, gasoline and diesel fuel to approximately 42,000 customers on a delivery only basis. In addition, Petro installed, maintained, and repaired heating and air conditioning equipment for its customers, and provided ancillary home services, including home security and plumbing, to approximately 11,500 customers.

•

Star Gas Finance Company is a 100% owned subsidiary of the Partnership. Star Gas Finance Company serves as the co-issuer, jointly and severally with the Partnership, of its $125 million (excluding discount) 8.875% Senior Notes outstanding at December 31, 2011, that are due 2017. The Partnership is dependent on distributions including inter-company interest payments from its subsidiaries to service the Partnership’s debt obligations. The distributions from the Partnership’s subsidiaries are not guaranteed and are subject to certain loan restrictions. Star Gas Finance Company has nominal assets and conducts no business operations. (See Note 6—Long-Term Debt and Bank Facility Borrowings)

2) Common Unit Repurchase and Retirement

In July 2010, the Board of Directors of the Partnership’s General Partner (“BOD”) authorized the repurchase of up to 7.0 million of the Partnership’s common units (“Plan II”). In December 2011, the BOD authorized the repurchase of an additional 250 thousand common units. The authorized common unit repurchases may be made from time-to-time in the open market, in privately negotiated transactions or in such other manner deemed appropriate by management. In order to facilitate the repurchase program, the Partnership entered into a prearranged unit repurchase plan under Rule 10b5-1 of the Securities Act of 1933, as amended, for up to 4.0 million common units with a third party broker. There is no guarantee of the exact number of units that will be purchased under the program and the Partnership may discontinue purchases at any time. The program does not have a time limit. The Partnership’s repurchase activities take into account SEC safe harbor rules and guidance for issuer repurchases. As of December 31, 2011, 5.8 million common units authorized for repurchase under Plan II were repurchased at an average price paid per unit of $5.02. (See Note 10 - Subsequent Events, Common Unit Repurchase and Retirement)


(in thousands, except per unit amounts)
Period	Total Number of Units Purchased as Part of a Publicly Announced Plan or Program		Average Price Paid per Unit (b)		Maximum Number of Units that May Yet Be Purchased Under the Plan II Program

Plan II - Number of units authorized (a)						7,250


Plan II - Fiscal year 2010 total		1,197	$	4.44		6,053




Plan II - Fiscal year 2011 total (c)		2,108	$	5.19		3,945


Plan II - October 2011		226	$	4.96		3,719
Plan II - November 2011		215	$	4.95		3,504
Plan II - December 2011 (d)		2,007	$	5.21		1,497


Plan II - First quarter fiscal year 2012 total		2,448	$	5.17		1,497

(a)	In July 2010, the BOD authorized 7.0 million common units for repurchase. In December 2011, the BOD authorized an additional 250 thousand common units for repurchase.

(b)	Amounts include repurchase costs.

(c)	Fiscal year 2011 common unit repurchase include 1.5 million common units acquired in a private sale.

(d)	December 2011 common unit repurchase include 1.75 million common units acquired in a private sale.

3) Summary of Significant Accounting Policies

Basis of Presentation

The Consolidated Financial Statements include the accounts of Star Gas Partners, L.P. and its subsidiaries. All material inter-company items and transactions have been eliminated in consolidation.

The financial information included herein is unaudited; however, such information reflects all adjustments (consisting solely of normal recurring adjustments), which are, in the opinion of management, necessary for the fair statement of financial condition and results for the interim periods. Due to the seasonal nature of the Partnership’s business, the results of operations and cash flows for the three month period ended December 31, 2011 and December 31, 2010 are not necessarily indicative of the results to be expected for the full year.

These interim financial statements of the Partnership have been prepared in accordance with accounting principles generally accepted in the United States for interim financial information and Rule 10-01 of Regulation S-X of the U.S. Securities and Exchange Commission and should be read in conjunction with the financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended September 30, 2011.

Use of Estimates

The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America 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 revenue and expenses during the reporting period. Actual results could differ from those estimates.

Revenue Recognition

Sales of heating oil and other fuels are recognized at the time of delivery of the product to the customer and sales of heating and air conditioning equipment are recognized at the time of installation. Revenue from repairs and maintenance service is recognized upon completion of the service. Payments received from customers for equipment service contracts are deferred and amortized into income over the terms of the respective service contracts, on a straight-line basis, which generally do not exceed one year. To the extent that the Partnership anticipates that future costs for fulfilling its contractual obligations under its service maintenance contracts will exceed the amount of deferred revenue currently attributable to these contracts, the Partnership recognizes a loss in current period earnings equal to the amount that anticipated future costs exceed related deferred revenues.

Cost of Product

Cost of product includes the cost of heating oil, diesel, propane, kerosene, heavy oil, gasoline, throughput costs, barging costs, option costs, and realized gains/losses on closed derivative positions for product sales.

Cost of Installations and Service

Cost of installations and service includes equipment and material costs, wages and benefits for equipment technicians, dispatchers and other support personnel, subcontractor expenses, commissions and vehicle related costs.

Delivery and Branch Expenses

Delivery and branch expenses include wages and benefits and department related costs for drivers, dispatchers, garage mechanics, customer service, sales and marketing, compliance, credit and branch accounting, information technology, insurance and operational support.

General and Administrative Expenses

General and administrative expenses include wages and benefits and department related costs for human resources, finance and partnership accounting, administrative support and supply.

Allowance for Doubtful Accounts

The allowance for doubtful accounts, which includes the allowance for long-term receivables, is the Partnership’s best estimate of the amount of trade receivables that may not be collectible. The allowance is determined at an aggregate level by grouping accounts based on the type of account and its receivable aging. The allowance is based on both quantitative and qualitative factors, including historical loss experience, historical collection patterns, overdue status, aging trends, and current economic conditions. The Partnership has an established process to periodically review current and past due trade receivable balances to determine the adequacy of the allowance. No single statistic or measurement determines the adequacy of the allowance. The total allowance reflects management’s estimate of losses inherent in its trade receivables at the balance sheet date. Different assumptions or changes in economic conditions could result in material changes to the allowance for doubtful accounts.

Allocation of Net Income

Net income for partners’ capital and statement of operations is allocated to the general partner and the limited partners in accordance with their respective ownership percentages, after giving effect to cash distributions paid to the general partner in excess of its ownership interest, if any.

Net Income per Limited Partner Unit

Income per limited partner unit is computed in accordance with FASB ASC 260-10-05 Earnings Per Share topic, Master Limited Partnerships subtopic (EITF 03-06), by dividing the limited partners’ interest in net income by the weighted average number of limited partner units outstanding. The pro forma nature of the allocation required by this standard provides that in any accounting period where the Partnership’s aggregate net income exceeds its aggregate distribution for such period, the Partnership is required to present net income per limited partner unit as if all of the earnings for the periods were distributed, regardless of whether those earnings would actually be distributed during a particular period from an economic or practical perspective. This allocation does not impact the Partnership’s overall net income or other financial results. However, for periods in which the Partnership’s aggregate net income exceeds its aggregate distributions for such period, it will have the impact of reducing the earnings per limited partner unit, as the calculation according to this standard results in a theoretical increased allocation of undistributed earnings to the general partner. In accounting periods where aggregate net income does not exceed aggregate distributions for such period, this standard does not have any impact on the Partnership’s net income per limited partner unit calculation. A separate and independent calculation for each quarter and year-to-date period is performed, in which the Partnership’s contractual participation rights are taken into account.

The following presents the net income allocation and per unit data using this method for the periods presented:


Basic and Diluted Earnings Per Limited Partner:	Three Months Ended December 31,
(in thousands, except per unit data)	2011		2010
Net income	$	2,931	$	20,558
Less General Partners’ interest in net income		15		99

Net income available to limited partners		2,916		20,459

Less dilutive impact of theoretical distribution of earnings under FASB ASC 260-10-45-60		—		2,774

Limited Partner’s interest in net income under FASB ASC 260-10-45-60	$	2,916	$	17,685


Per unit data:
Basic and diluted net income available to limited partners	$	0.05	$	0.30

Less dilutive impact of theoretical distribution of earnings under FASB ASC 260-10-45-60		—		0.04

Limited Partner’s interest in net income under FASB ASC 260-10-45-60	$	0.05	$	0.26


Weighted average number of Limited Partner units outstanding		64,189		67,078

Cash Equivalents, Accounts Receivable, Revolving Credit Facility Borrowings, and Accounts Payable

The carrying amount of cash equivalents, accounts receivable, revolving credit facility borrowings, and accounts payable approximates fair value because of the short maturity of these instruments.

Cash Equivalents

The Partnership considers all highly liquid investments with an original maturity of three months or less, when purchased, to be cash equivalents.

Inventories

The Partnership’s inventory of heating oil and other fuels are stated at the lower of cost computed on the weighted average cost (WAC) method, or market. All other inventories, representing parts and equipment are stated at the lower of cost computed on the FIFO method, or market.


(in thousands)	December 31, 2011		September 30, 2011

Liquid product	$	84,030	$	64,907
Parts and equipment		16,475		15,629

	$	100,505	$	80,536

Derivatives and Hedging – Disclosures and Fair Value Measurements

The Partnership uses derivative instruments such as futures, options, and swap agreements, in order to mitigate exposure to market risk associated with the purchase of home heating oil for price-protected customers, physical inventory on hand, inventory in transit and priced purchase commitments.

To hedge a substantial majority of the purchase price associated with heating oil gallons anticipated to be sold to its price-protected customers, as of December 31, 2011, the Partnership had 2.0 million gallons of physical inventory and had 8.1 million gallons of swap contracts to buy heating oil; 4.0 million gallons of call options; 5.8 million gallons of put options and 90.2 million net gallons of synthetic calls. To hedge the inter-month differentials for our price-protected customers, its physical inventory on hand, and inventory in transit, the Partnership as of December 31, 2011 had 17.5 million gallons of future contracts to buy heating oil; 26.5 million gallons of future contracts to sell heating oil; and 27.8 million gallons of swap contracts to sell heating oil. To hedge a portion of its internal fuel usage, the Partnership as of December 31, 2011, had 1.3 million gallons of swap contracts to buy gasoline; and 1.0 million gallons of swap contracts to buy diesel.

To hedge a substantial majority of the purchase price associated with heating oil gallons anticipated to be sold to its price-protected customers, as of December 31, 2010, the Partnership had 2.9 million gallons of physical inventory and had 6.6 million gallons of swap contracts to buy heating oil; 34.0 million gallons of call options; 5.6 million gallons of put options and 64.0 million net gallons of synthetic calls. To hedge the inter-month differentials for our price-protected customers, its physical inventory on hand, and inventory in transit, the Partnership as of December 31, 2010 had 14.1 million gallons of future contracts to buy heating oil; 22.0 million gallons of future contracts to sell heating oil; and 29.4 million gallons of swap contracts to sell heating oil. To hedge a portion of its internal fuel usage, the Partnership as of December 31, 2010, had 1.1 million gallons of swap contracts to buy gasoline; and 0.9 million gallons of swap contracts to buy diesel.

The Partnership’s derivative instruments are with the following counterparties: Key Bank, N.A., Societe Generale, Cargill, Inc., JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A., Bank of Montreal, Bank of America, N.A., Regions Financial Corporation, and Newedge USA, LLC. The Partnership assesses counterparty credit risk and maintains master netting arrangements with its counterparties to help manage the risks, and records its derivative positions on a net basis. The Partnership considers counterparty credit risk to be low. At December 31, 2011, the aggregate cash posted as collateral in the normal course of business at counterparties was $2.2 million. Positions with counterparties who are also parties to our revolving credit facility are collateralized under that facility. As of December 31, 2011, $16.1 million of hedging losses was secured under the credit facility.

FASB ASC 815-10-05 Derivatives and Hedging topic, established accounting and reporting standards requiring that derivative instruments be recorded at fair value and included in the consolidated balance sheet as assets or liabilities, along with qualitative disclosures regarding the derivative activity. To the extent derivative instruments designated as cash flow hedges are effective and the standard’s documentation requirements have been met, changes in fair value are recognized in other comprehensive income until the underlying hedged item is recognized in earnings. The Partnership has elected not to designate its derivative instruments as hedging instruments under this standard and the change in fair value of the derivative instruments is recognized in our statement of operations in the line item (Increase) decrease in the fair value of derivative instruments. Realized gains and losses are recorded in cost of product.

FASB ASC 820-10 Fair Value Measurements and Disclosures topic, established a three-tier fair value hierarchy, which classified the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices for identical instruments in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. The Partnership’s Level 1 derivative assets and liabilities represent the fair value of commodity contracts used in its hedging activities that are identical and traded in active markets. The Partnership’s Level 2 derivative assets and liabilities represent the fair value of commodity contracts used in its hedging activities that are valued using either directly or indirectly observable inputs, whose nature, risk and class are similar. No significant transfers of assets or liabilities have been made into and out of the Level 1 or Level 2 tiers. All derivative instruments were non-trading positions. The market prices used to value the Partnership’s derivatives have been determined using the New York Mercantile Exchange (“NYMEX”) and independent third party prices that are reviewed for reasonableness.

The Partnership had no assets or liabilities that are measured at fair value on a nonrecurring basis subsequent to their initial recognition. The Partnership’s financial assets and liabilities measured at fair value on a recurring basis are listed on the following table.


(In thousands)					Fair Value Measurements at Reporting Date Using:
Derivatives Not Designated as Hedging Instruments Under FASB ASC 815-10	Balance Sheet Location	Total			Quoted Prices in Active Markets for Identical Assets Level 1			Significant Other Observable Inputs Level 2			Significant Unobservable Inputs Level 3

Asset Derivatives at December 31, 2011
Commodity contracts	Fair asset and fair liability value of derivative instruments	$	22,565		$	29		$	22,536		$	—
Commodity contracts	Long-term derivative assets included in the deferred charges and other assets, net balance		784			365			419			—

Commodity contract assets at December 31, 2011		$	23,349		$	394		$	22,955		$	—


Liability Derivatives at December 31, 2011
Commodity contracts	Fair liability and fair asset value of derivative instruments	$	(30,687	)	$	(770	)	$	(29,917	)	$	—
Commodity contracts	Long-term derivative liabilities included in other long-term liabilities		(530	)		(109	)		(421	)		—

Commodity contract liabilities at December 31, 2011		$	(31,217	)	$	(879	)	$	(30,338	)	$	—


Asset Derivatives at September 30, 2011
Commodity contracts	Fair asset and fair liability value of derivative instruments	$	41,531		$	550		$	40,981		$	—
Commodity contracts	Long-term derivative assets included in the deferred charges and other assets, net balance		257			171			86			—

Commodity contract assets at September 30, 2011		$	41,788		$	721		$	41,067		$	—


Liability Derivatives at September 30, 2011
Commodity contracts	Fair liability and fair asset value of derivative instruments	$	(41,179	)	$	(602	)	$	(40,577	)	$	—
Commodity contracts	Long-term derivative liabilities netted with the deferred charges and other assets, net balance		(96	)		(25	)		(71	)		—

Commodity contract liabilities at September 30, 2011		$	(41,275	)	$	(627	)	$	(40,648	)	$	—


(In thousands)
The Effect of Derivative Instruments on the Statement of Operations
		Amount of (Gain) or Loss Recognized in Income on Derivative
Derivatives Not Designated as Hedging Instruments Under FASB ASC 815-10	Location of (Gain) or Loss Recognized in Income on Derivative	Three Months Ended December 31, 2011			Three Months Ended December 31, 2010

Commodity contracts	Cost of product (a)	$	(592	)	$	9,742
Commodity contracts	Cost of installations and service (a)	$	51		$	(93	)
Commodity contracts	Delivery and branch expenses (a)	$	8		$	(103	)

Commodity contracts	(Increase) / decrease in the fair value of derivative instruments	$	7,118		$	(13,906	)

(a)	Represents realized closed positions and includes the cost of options as they expire.

Weather Hedge Contract

Weather hedge contract is recorded in accordance with the intrinsic value method defined by FASB ASC 815-45-15 Derivatives and Hedging topic, Weather Derivatives subtopic (EITF 99-2). The premium paid is amortized over the life of the contract and the intrinsic value method is applied at each interim period.

Property and Equipment, net

Property and equipment are stated at cost. Depreciation is computed over the estimated useful lives of the depreciable assets using the straight-line method.


(in thousands)	December 31, 2011		September 30, 2011

Property and equipment	$	162,258	$	155,426
Less: accumulated depreciation		109,962		108,295

Property and equipment, net	$	52,296	$	47,131

Business Combinations

The Partnership uses the acquisition method of accounting in accordance with FASB ASC 805 Business Combinations. The acquisition method of accounting requires the Partnership to use significant estimates and assumptions, including fair value estimates, as of the business combination date, and to refine those estimates as necessary during the measurement period (defined as the period, not to exceed one year, in which the amounts recognized for a business combination may be adjusted). Each acquired company’s operating results are included in the Partnership’s consolidated financial statements starting on the date of acquisition. The purchase price is equivalent to the fair value of consideration transferred. Tangible and identifiable intangible assets acquired and liabilities assumed as of the date of acquisition, are recorded at the acquisition date fair value. The separately identifiable intangible assets generally are comprised of customer lists, trade names and covenants not to compete. Goodwill is recognized for the excess of the purchase price over the net fair value of assets acquired and liabilities assumed.

Costs that are incurred to complete the business combination such as investment banking, legal and other professional fees are not considered part of consideration transferred, and are charged to general and administrative expense as they are incurred. For any given acquisition, certain contingent consideration may be identified. Estimates of the fair value of liability or asset classified contingent consideration are included under the acquisition method as part of the assets acquired or liabilities assumed. At each reporting date, these estimates are remeasured to fair value, with changes recognized in earnings.

Goodwill and Intangible Assets

Goodwill and intangible assets include goodwill, customer lists, trade names and covenants not to compete.

Goodwill is the excess of cost over the fair value of net assets in the acquisition of a company. Under FASB ASC 350-10-05 Intangibles-Goodwill and Other, a potential goodwill impairment is deemed to exist if the net book value of a reporting unit exceeds its estimated fair value. If goodwill of a reporting unit is determined to be impaired, the amount of impairment is measured based on the excess of the net book value of the goodwill over the implied fair value of the goodwill.

The Partnership has selected August 31 of each year to perform its annual impairment review under this standard. The evaluations utilize an Income Approach and Market Approach (consisting of the Market Comparable and the Market Transaction Approach), which contain reasonable and supportable assumptions and projections reflecting management’s best estimate in deriving the Partnership’s total enterprise value. The Income Approach calculates over a discrete period the free cash flow generated by the Partnership to determine the enterprise value. The Market Comparable approach compares the Partnership to comparable companies in similar industries to determine the enterprise value. The Market Transaction approach uses exchange prices in actual sales and purchases of comparable businesses to determine the enterprise value.

The total enterprise value as indicated by these two approaches is compared to the Partnership’s book value (one reporting unit) of net assets and reviewed in light of the Partnership’s market capitalization.

Customer lists are the names and addresses of an acquired company’s customers. Based on historical retention experience, these lists are amortized on a straight-line basis over seven to ten years.

Trade names are the names of acquired companies. Based on the economic benefit expected and historical retention experience of customers, trade names are amortized on a straight-line basis over seven to twenty years.

Covenants not to compete are agreements with the owners of acquired companies and are amortized over the respective lives of the covenants on a straight-line basis, which are generally five years.

Partners’ Capital

Comprehensive income includes net income, plus certain other items that are recorded directly to partners’ capital. Accumulated other comprehensive income reported on the Partnerships’ consolidated balance sheets consists of unrealized gains/losses on pension plan obligations and the tax affect. For the three months ended December 31, 2011, comprehensive income was $3.3 million, comprised of net income of $2.9 million, an unrealized gain on pension plan obligation of $0.7 million and the tax effect of $(0.3) million. For the three months ended December 31, 2010, comprehensive income was $21.0 million, comprised of net income of $20.6 million, an unrealized gain on pension plan obligation of $0.7 million and the tax affect of $(0.3) million.

Income Taxes

The Partnership is a master limited partnership and is not subject to tax at the entity level for Federal and State income tax purposes. Rather, income and losses of the Partnership are allocated directly to the individual partners (the Partnership’s corporate subsidiaries are subject to tax at the entity level for federal and state income tax purposes). While the Partnership will generate non-qualifying Master Limited Partnership revenue through its corporate subsidiaries, distributions from the corporate subsidiaries to the Partnership are generally included in the determination of qualified Master Limited Partnership income. All or a portion of the distributions received by the Partnership from the corporate subsidiaries could be a dividend or capital gain to the partners.

The accompanying financial statements are reported on a fiscal year, however, the Partnership and its Corporate subsidiaries file Federal and State income tax returns on a calendar year.

As most of the Partnership’s income is derived from its corporate subsidiaries, these financial statements reflect significant Federal and State income taxes. For corporate subsidiaries of the Partnership, a consolidated Federal income tax return is filed. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amount of assets and liabilities and their respective tax bases and operating loss carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. A valuation allowance is recognized if, based on the weight of available evidence including historical tax losses, it is more likely than not that some or all of deferred tax assets will not be realized.

The current and deferred income tax expenses for the three months ended December 31, 2011, and 2010 are as follows:


	Three Months Ended December 31,
(in thousands)	2011		2010

Income before income taxes	$	5,583	$	37,569

Current tax expense	$	1,498	$	2,031
Deferred tax expense		1,154		14,980

Total tax expense	$	2,652	$	17,011

As of the calendar tax year ended December 31, 2011, Star Acquisitions, a wholly-owned subsidiary of the Partnership, had an estimated Federal net operating loss carry forward (“NOL”) of approximately $12.8 million. The Federal NOLs, which will expire between 2018 and 2024, are generally available to offset any future taxable income but are also subject to annual limitations of between $1.0 million and $2.2 million.

FASB ASC 740-10-05-6 Income Taxes topic, Uncertain Tax Position subtopic (SFAS No. 109 and FIN 48), provides financial statement accounting guidance for uncertainty in income taxes and tax positions taken or expected to be taken in a tax return. At December 31, 2011, we had unrecognized income tax benefits totaling $2.8 million including related accrued interest and penalties of $0.5 million. These unrecognized tax benefits are primarily the result of Federal tax uncertainties. If recognized, these tax benefits and related interest and penalties would be recorded as a benefit to the effective tax rate.

We believe that the total liability for unrecognized tax benefits will not materially change during the next 12 months ending December 31, 2012. Our continuing practice is to recognize interest and penalties related to income tax matters as a component of income tax expense.

We file U.S. Federal income tax returns and various state and local returns. A number of years may elapse before an uncertain tax position is audited and finally resolved. For our Federal income tax returns we have four tax years subject to examination. In our major state tax jurisdictions of New York, Connecticut, Pennsylvania and New Jersey, we have four, four, five, and five tax years, respectively, that are subject to examination. While it is often difficult to predict the final outcome or the timing of resolution of any particular uncertain tax position, based on our assessment of many factors including past experience and interpretation of tax law, we believe that our provision for income taxes reflect the most probable outcome. This assessment relies on estimates and assumptions and may involve a series of complex judgments about future events.

Sales, Use and Value Added Taxes

Taxes are assessed by various governmental authorities on many different types of transactions. Sales reported for product, installation and service exclude taxes.

Recent Accounting Pronouncements

In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-04, Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. generally accepted accounting principles (“U.S. GAAP”) and the International Financial Reporting Standards (“IFRS”), that results in a consistent definition of fair value and common requirements for measurement of and disclosure about fair value. The new guidance clarifies and changes some fair value measurement principles and disclosure requirements under U.S. GAAP. Among them is the clarification that the concepts of highest and best use and valuation premise in a fair value measurement, should only be applied when measuring the fair value of nonfinancial assets. Additionally, the new guidance requires quantitative information about unobservable inputs, disclosure of the valuation processes used and narrative descriptions with regard to fair value measurements within the Level 3 categorization of the fair value hierarchy. The new guidance is effective for interim and annual reporting periods beginning after December 15, 2011, with early adoption prohibited. The adoption of this new guidance is not expected to have a material impact on the Partnership’s Consolidated Financial Statements.

In June 2011, the FASB issued ASU No. 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income, and subsequently deferred the requirement to separately present within net income reclassification adjustments of items out of accumulated other comprehensive income. This standard eliminates the option to present items of other comprehensive income (“OCI”) as part of the statement of changes in stockholders’ equity, and instead requires either OCI presentation and net income in a single continuous statement to the statement of operations, or as a separate statement of comprehensive income. ASU No. 2011-05 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011, with early adoption permitted. The Partnership is required to adopt this update in the first quarter of fiscal year 2013. The adoption of ASU No. 2011-05 will not impact our results of operations or the amount of assets and liabilities reported.

In September 2011, the FASB issued ASU No. 2011-08, Intangibles-Goodwill and Other (Topic 350): Testing Goodwill for Impairment. This standard simplifies how entities test goodwill for impairment by providing for an optional qualitative assessment in determining whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount, as a basis for determining whether it is necessary to perform the first step, of the two-step goodwill impairment test. The new guidance is effective for annual and interim goodwill impairment tests performed in fiscal years beginning after December 15, 2011, with early adoption permitted. The Partnership has not early adopted this standard and is required to adopt this update in fiscal year 2013. The adoption of ASU No. 2011-08 will not impact our results of operations or the amount of assets and liabilities reported.

In September 2011, the FASB issued ASU No. 2011-09, Compensation—Retirement Benefits—Multiemployer Plans (Subtopic 715-80): Disclosures about an Employer’s Participation in a Multiemployer Plan. This standard requires employers that participate in multiemployer pension plans to provide additional quantitative and qualitative disclosures such as significant multiemployer plan names, identifying number, employer contributions, an indication of the plan’s funded status, and the nature of the employer commitments to the plan. The new guidance is effective for annual periods for fiscal years ending after December 15, 2011, with early adoption permitted. The Partnership has not early adopted this standard and is required to adopt it in fiscal year 2012. The adoption of ASU No. 2011-09 will not impact our results of operations or the amount of assets and liabilities reported.

4) Goodwill and Intangibles, net

Goodwill

A summary of changes in the Partnership’s goodwill is as follows (in thousands):


Balance as of September 30, 2011	$	199,296
Fiscal year 2012 acquisitions		6,170

Balance as of December 31, 2011	$	205,466

The Partnership performed its annual goodwill impairment valuation for the period ending August 31, 2011 and determined that there was no goodwill impairment. The preparation of this analysis (see Note 3. Summary of Significant Accounting Policies – Goodwill and Intangible Assets) was based upon management’s estimates and assumptions, and future impairment calculations would be affected by actual results that are materially different from projected amounts. To provide for a sensitivity of the discount rates and transaction multiples used, ranges of high and low values are employed in the analysis, with the low values examined to ensure that a reasonably likely change in an assumption would not cause the Partnership to reach a different conclusion.

Intangibles, net

The gross carrying amount and accumulated amortization of intangible assets subject to amortization are as follows:


	December 31, 2011						September 30, 2011
(in thousands)	Gross Carrying Amount		Accum. Amortization		Net		Gross Carrying Amount		Accum. Amortization		Net

Customer lists and other intangibles	$	266,075	$	205,505	$	60,570	$	256,172	$	203,824	$	52,348

Amortization expense for intangible assets was $1.7 million for the three months ended December 31, 2011 compared to $2.8 million for the three months ended December 31, 2010. Total estimated annual amortization expense related to intangible assets subject to amortization, for the fiscal year ending September 30, 2012 and the four succeeding fiscal years ending September 30, is as follows (in thousands):


	Estimated Annual Book Amortization Expense
2012	$	6,878
2013	$	7,099
2014	$	7,023
2015	$	6,887
2016	$	6,717

5) Business Combinations

During the three months ended December 31, 2011, the Partnership acquired three heating oil and propane dealers. The aggregate purchase price was approximately $25.9 million, including working capital of $3.9 million. The operating results of these three acquisitions have been included in the Partnership’s consolidated financial statements since the date of acquisition, and are not material to the Partnership’s financial condition, results of operations, or cash flows. Preliminary fair values of the assets acquired and liabilities assumed are comprised primarily of intangibles and certain working capital items, which are reflected in the Consolidated Balance Sheet as of December 31, 2011, and are pending final valuation within the permitted measurement period.

6) Long-Term Debt and Bank Facility Borrowings

The Partnership’s debt is as follows (in thousands):


	At December 31, 2011				At September 30, 2011
	Carrying Amount		Estimated Fair Value (a)		Carrying Amount		Estimated Fair Value (a)
8.875% Senior Notes (b)	$	124,286	$	126,875	$	124,263	$	127,500

Revolving Credit Facility Borrowings (c )		46,834		46,834		—		—

Total debt	$	171,120	$	173,709	$	124,263	$	127,500

Total long-term portion of debt	$	124,286	$	126,875	$	124,263	$	127,500

(a)

The Partnership’s fair value estimates of long-term debt are made at a specific point in time, based on relevant market information, open market quotations and information about the financial instrument. These estimates are subjective in nature and involve uncertainties and matters of significant judgment. Changes in assumptions could significantly affect the estimates.

(b)

The 8.875% Senior Notes were originally issued in November 2010 in a private placement offering pursuant to Rule 144A and Regulation S under the Securities Act of 1933, and in February 2011, were exchanged for substantially identical public notes registered with the Securities and Exchange Commission. These public notes mature in December 2017 and accrue interest at an annual rate of 8.875% requiring semi-annual interest payments on June 1 and December 1 of each year. The discount on these notes was $0.7 million at December 31, 2011. Under the terms of the indenture, these notes permit restricted payments after passing certain financial tests. The Partnership can incur debt up to $100 million for acquisitions and can also pay restricted payments of $22.0 million without passing certain financial tests.

(c)

In June 2011, the Partnership entered into an amended and restated asset based revolving credit facility agreement with a bank syndication comprised of fifteen banks. The amended and restated revolving credit facility expires in June 2016. In November 2011, the Partnership exercised the provision under this agreement to expand the facility by an additional $50 million. Under this agreement, the Partnership may borrow up to $250 million ($350 million during the heating season from December to April each year) for working capital purposes (subject to certain borrowing base limitations and coverage ratios) and may issue up to $100 million in letters of credit. The Partnership can increase the facility size by $100 million without the consent of the bank group. The bank group is not obligated to fund the $100 million increase. If the bank group elects not to fund the increase, the Partnership can add additional lenders to the group, with the consent of the agent (as appointed in the revolving credit facility agreement), which shall not be unreasonably withheld.

Obligations under the revolving credit facility are guaranteed by the Partnership and its subsidiaries and are secured by liens on substantially all of the Partnership’s assets including accounts receivable, inventory, general intangibles, real property, fixtures and equipment.

The interest rate is LIBOR plus (i) 1.75% (if availability, as defined in the revolving credit facility agreement is greater than or equal to $150 million), or (ii) 2.00% (if availability is greater than $75 million but less than $150 million), or (iii) 2.25% (if availability is less than or equal to $75 million). The commitment fee on the unused portion of the facility is 0.375% per annum. This amended and restated revolving credit facility imposes certain restrictions, including restrictions on the Partnership’s ability to incur additional indebtedness, to pay distributions to unitholders, to pay inter-company dividends or distributions, make investments, grant liens, sell assets, make acquisitions and engage in certain other activities.

The Partnership is obligated to meet certain financial covenants under the amended and restated revolving credit facility, including the requirement to maintain at all times either availability (borrowing base less amounts borrowed and letters of credit issued) of $43.8 million, 12.5% of the maximum facility size, or a fixed charge coverage ratio (as defined in the revolving credit facility agreement) of not less than 1.1, which is calculated based upon Adjusted EBITDA. In order to make acquisitions, the Partnership must maintain availability of $40 million on a historical pro forma and forward-looking basis. In addition, the Partnership must maintain availability of $61.3 million, 17.5% of the maximum facility size on a historical pro forma and forward-looking basis, and a fixed charge coverage ratio of not less than 1.15 in order to pay any distributions to unitholders or repurchase common units. Certain activities including investments, acquisitions, asset sales, inter-company dividends or distributions cannot be made (including those needed to pay interest or principal on the 8.875% senior notes), except to the Partnership or a wholly owned subsidiary of the Partnership, if the relevant covenant described above has not been met. The occurrence of an event of default or an acceleration under the amended and restated revolving credit facility would result in the Partnership’s inability to obtain further borrowings under that facility, which could adversely affect its results of operations. Such a default may also restrict the ability of the Partnership to obtain funds from its subsidiaries in order to pay interest or paydown debt. An acceleration under the amended and restated revolving credit facility would result in a default under the Partnership’s other funded debt.

At December 31, 2011, $46.8 million was outstanding under the revolving credit facility and $46.3 million of letters of credit were issued. At September 30, 2011, no amount was outstanding under the revolving credit facility and $46.7 million of letters of credit were issued.

As of December 31, 2011, availability was $128.1 million and the Partnership was in compliance with the fixed charge coverage ratio. At September 30, 2011, availability was $162.4 million and the Partnership was in compliance with the fixed charge coverage ratio.

In July 2011, the Partnership’s shelf registration became effective, providing for the sale of up to $250 million in one or more offerings of common units representing limited partnership interests, partnership securities and debt securities; which may be secured or unsecured senior debt securities or secured or unsecured subordinated debt securities. As of December 30, 2011, no offerings under this shelf registration have occurred.

7) Employee Pension Plan


	Three Months Ended December 31,
(in thousands)	2011			2010

Components of net periodic benefit cost:
Service cost	$	—		$	—
Interest cost		714			748
Expected return on plan assets		(941	)		(879	)
Net amortization		688			691

Net periodic benefit cost	$	461		$	560

For the three months ended December 31, 2011, the Partnership contributed $0.7 million and expects to make an additional $2.7 million contribution in fiscal 2012 to fund its pension obligation.

8) Supplemental Disclosure of Cash Flow Information


	Three Months Ended December 31,
(in thousands)	2011		2010

Cash paid during the period for:
Income taxes, net	$	243	$	117
Interest	$	6,038	$	3,829
Debt redemption premium	$	—	$	1,409
Non-cash financing activities:
Increase (decrease) in interest expense—amortization of debt discount 8.875% and debt premium 10.25%	$	23	$	(13	)
Decrease in net debt premium attributable to redemption of debt	$	—	$	247

9) Commitments and Contingencies

The Partnership’s operations are subject to all operating hazards and risks normally incidental to handling, storing and transporting and otherwise providing for use by consumers of combustible liquids such as home heating oil and propane. As a result, at any given time the Partnership is a defendant in various legal proceedings and litigation arising in the ordinary course of business. The Partnership maintains insurance policies with insurers in amounts and with coverages and deductibles we believe are reasonable and prudent. However, the Partnership cannot assure that this insurance will be adequate to protect it from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices. In the opinion of management the Partnership is not a party to any litigation, which individually or in the aggregate could reasonably be expected to have a material adverse effect on the Partnership’s results of operations, financial position or liquidity.

10) Subsequent Events

Quarterly Distribution Declared

On January 19, 2012, the Partnership declared a quarterly distribution of $0.0775 per unit, or $0.31 per unit on an annualized basis, on all common units in respect of the first quarter of fiscal 2012 payable on February 7, 2012, to holders of record on January 30, 2012. In accordance with our Partnership Agreement, the amount of distributions in excess of the minimum quarterly distribution of $0.0675, are distributed 90% to the holders of common units and 10% to the holders of the General Partner units (until certain distribution levels are met), subject to the management incentive compensation plan. As a result, $4.8 million was paid to the common unit holders, $0.06 million was paid to the General Partner and $0.03 million was paid to management pursuant to the management incentive compensation plan.

Common Unit Repurchase and Retirement

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Statement Regarding Forward-Looking Disclosure

This Quarterly Report on Form 10-Q includes “forward-looking statements” which represent our expectations or beliefs concerning future events that involve risks and uncertainties, including those associated with the effect of weather conditions on our financial performance, the price and supply of the products that we sell, the consumption patterns of our customers, our ability to obtain satisfactory gross profit margins, our ability to obtain new customers and retain existing customers, our ability to make strategic acquisitions, the impact of litigation, our ability to contract for our current and future supply needs, natural gas conversions, future union relations and the outcome of current and future union negotiations, the impact of current and future governmental regulations, including environmental, health, and safety regulations, the ability to attract and retain employees, customer credit worthiness, counterparty credit worthiness, marketing plans, general economic conditions and new technology. All statements other than statements of historical facts included in this Report including, without limitation, the statements under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere herein, are forward-looking statements. Without limiting the foregoing, the words “believe,” “anticipate,” “plan,” “expect,” “seek,” “estimate,” and similar expressions are intended to identify forward-looking statements. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to be correct and actual results may differ materially from those projected as a result of certain risks and uncertainties. These risks and uncertainties include, but are not limited to, those set forth under the heading “Risk Factors” and “Business Strategy” in our Annual Report on Form 10-K (the “Form 10-K”) for the fiscal year ended September 30, 2011 and under the heading “Risk Factors” in this Quarterly Report on Form 10-Q. Important factors that could cause actual results to differ materially from our expectations (“Cautionary Statements”) are disclosed in the Form 10-K and in this Quarterly Report on Form 10-Q. 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. Unless otherwise required by law, we undertake no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise after the date of this Report.

Overview

The following is a discussion of the historical financial condition and results of our operations and should be read in conjunction with the description of our business in Item 1. “Business” of the Form 10-K and the historical financial and operating data and notes thereto included elsewhere in this Report.

Seasonality

The following matters should be considered in analyzing our financial results. Our fiscal year ends on September 30. All references to quarters and years respectively in this document are to fiscal quarters and years unless otherwise noted. The seasonal nature of our business has resulted, on average during the last five years, in the sale of approximately 30% of our volume of home heating oil and propane in the first fiscal quarter and 50% of our volume in the second fiscal quarter of each fiscal year, the peak heating season. We generally realize net income in both of these quarters and net losses during the quarters ending June and September. In addition, sales volume typically fluctuates from year to year in response to variations in weather, wholesale energy prices and other factors.

Degree Day

A “degree day” is an industry measurement of temperature designed to evaluate energy demand and consumption. Degree days are based on how far the average temperature departs from 65°F. Each degree of temperature above 65°F is counted as one cooling degree day, and each degree of temperature below 65°F is counted as one heating degree day. Degree days are accumulated each day over the course of a year and can be compared to a monthly or a long-term (multi-year) average to see if a month or a year was warmer or cooler than usual. Degree days are officially observed by the National Weather Service.

Weather Volatility

The core of our heating season commences on November 1. Over the last 30 years, the variation in temperatures in our geographic areas of operations for the two month period ended December 31, have ranged from 23.1% warmer than normal to 28.3% colder than normal. For example the period from November 1, 2011 to December 31, 2011 was the third warmest over the last 30 years, and the period from November 1, 2010 to December 31, 2010 was the fourth coldest. In addition for the two months ended December 31, 2011, temperatures in such areas of operations were 27.2% warmer than the two months ended December 31, 2010, and 21.4% warmer than normal.

Home Heating Oil Price Volatility

In recent years, the wholesale price of home heating oil has been extremely volatile, resulting in increased consumer price sensitivity to heating costs and increased gross customer attrition. As a commodity, the price of home heating oil is generally impacted by many factors, including economic and geopolitical forces. The price of home heating oil is closely linked to the price refiners pay for crude oil, which is the principal cost component of home heating oil. The volatility in the wholesale cost of home heating oil, as measured by the New York Mercantile Exchange (“NYMEX”) price per gallon for fiscal 2012, 2011, 2010, 2009, and 2008 by quarter, is illustrated in the following chart:

Impact on Liquidity of Wholesale Product Cost Volatility


	Fiscal 2012				Fiscal 2011				Fiscal 2010				Fiscal 2009				Fiscal 2008
Quarter Ended	Low		High		Low		High		Low		High		Low		High		Low		High
December 31	$	2.72	$	3.17	$	2.19	$	2.54	$	1.78	$	2.12	$	1.20	$	2.85	$	2.16	$	2.71
March 31						2.49		3.09		1.89		2.20		1.13		1.63		2.42		3.15
June 30						2.75		3.32		1.87		2.35		1.31		1.86		2.88		3.97
September 30						2.77		3.13		1.92		2.24		1.50		1.96		2.72		4.11

Our liquidity is adversely impacted in times of increasing wholesale product costs, as we must use cash to fund our hedging requirements and a portion of the increased levels of accounts receivable and inventory. Our liquidity is also adversely impacted at times by sudden and sharp decreases in wholesale product costs due to the increased margin requirements for futures contracts and collateral requirements for options and swaps that we use to manage market risks related to our ceiling and fixed price customers and physical inventory that are not immediately offset by lower inventory and accounts receivable carrying costs.

Impact of Warm Weather on Operating Results; Weather Hedge Contract

Weather conditions have a significant impact on the demand for home heating oil and propane because our customers depend on these products principally for heating purposes. Actual weather conditions can vary substantially from year to year, significantly affecting our financial performance. To partially mitigate the adverse effect of warm weather on our cash flows, we have used weather hedging contracts for a number of years. For the fiscal 2012 heating season, we have entered into a weather hedge contract with Renaissance Trading Ltd. under which we are entitled to receive a payment of $35,000 per heating degree-day shortfall, when the total number of heating degree-days in the period covered is less than 92.5% of the ten year average (the “Payment Threshold”). The hedge covers the period from November 1, 2011 through March 31, 2012 taken as a whole, and has a maximum payout of $12.5 million.

While temperatures for November 1 to December 31, 2011 were warmer than the ten year average, the Partnership did not accrue any benefit from this weather contract for the first quarter of fiscal 2012 as the Payment Threshold had not been met as of the end of the first fiscal quarter. Temperatures for January 2012 were 13.9% warmer than the ten year average and 21.5% warmer than January 2011 which caused us to meet the Payment Threshold under the weather hedge contract as of January 31, 2012. Assuming that temperatures are equal to the ten year average during the remainder of the second fiscal quarter, we currently estimate that we would receive $3.3 million under the weather hedge contract. If temperatures in February and March 2012 are colder than the ten year average, then the expected payment under the weather hedge contract would be reduced or eliminated. If temperatures in February and March 2012 are warmer than the ten year average, then the expected payment under the weather hedge contract could increase up to a maximum of $12.5 million.

Per Gallon Gross Profit Margins

We believe the change in home heating oil and propane margins should be evaluated on a cents per gallon basis, before the effects of increases or decreases in the fair value of derivative instruments, as we believe that realized per gallon margins should not include the impact of non-cash changes in the market value of hedges before the settlement of the underlying transaction.

A significant portion of our home heating oil volume is sold to individual customers under an arrangement pre-establishing a ceiling sales price or fixed price for home heating oil over a fixed period of time (generally twelve months). When these price-protected customers agree to purchase home heating oil from us for the next heating season, we purchase option contracts, swaps and futures contracts for a substantial majority of the heating oil that we expect to sell to these customers. The amount of home heating oil volume that we hedge per price-protected customer is based upon the estimated fuel consumption per average customer, per month. In the event that the actual usage exceeds the amount of the hedged volume on a monthly basis, we may be required to obtain additional volume at unfavorable costs. In addition, should actual usage in any month be less than the hedged volume, our hedging losses could be greater, reducing expected margins.

Derivatives

are effective, as defined under this standard, changes in fair value are recognized in other comprehensive income until the forecasted hedged item is recognized in earnings. We have elected not to designate our derivative instruments as hedging instruments under this standard, and, as a result, the changes in fair value of the derivative instruments are recognized in our statement of operations. Therefore, we experience volatility in earnings as outstanding derivative instruments are marked to market and non-cash gains and losses are recorded prior to the sale of the commodity to the customer. The volatility in any given period related to unrealized non-cash gains or losses on derivative instruments can be significant to our overall results. However, we ultimately expect those gains and losses to be offset by the cost of product when purchased.

Income Taxes

Net Operating Loss Carry Forwards

At December 31, 2011, we estimate that our Federal Net Operating Loss carryforwards (“NOLs”) were $12.8 million subject to annual limitations of between $1.0 million and $2.2 million on the amount of such losses that can be used.

Book Versus Tax Deductions

The amount of cash flow that we generate in any given year depends upon a variety of factors including the amount of cash income taxes that our corporate subsidiaries are required to pay. The amount of depreciation and amortization that we deduct for book (i.e., financial reporting) purposes will differ from the amount that our subsidiaries can deduct for tax purposes. The table below compares the estimated depreciation and amortization for book purposes to the amount that our subsidiaries expect to deduct for tax purposes. Our subsidiaries file their tax returns based on a calendar year. The amounts below are based on our September 30, fiscal year.

Estimated Depreciation and Amortization Expense


(in thousands) Fiscal Year	Book		Tax
2012	$	16,399	$	32,537
2013		15,210		29,722
2014		13,793		25,014
2015		12,439		21,785
2016		10,922		16,355

Non-Deductible Partnership Expenses

In addition, the Partnership incurs approximately $2.0 million a year in general and administrative expenses that are not deductible for Federal or state income tax purposes.

EBITDA and Adjusted EBITDA (non-GAAP financial measures)

EBITDA (Earnings from continuing operations before net interest expense, income taxes, depreciation and amortization) and Adjusted EBITDA (Earnings from continuing operations before net interest expense, income taxes, depreciation and amortization, (increase) decrease in the fair value of derivatives, gain or loss on debt redemption, goodwill impairment, and other non-cash and non-operating charges) are non-GAAP financial measures that are used as supplemental financial measures by management and external users of our financial statements, such as investors, commercial banks and research analysts, to assess:

•

our compliance with certain financial covenants included in our debt agreements;

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our financial performance without regard to financing methods, capital structure, income taxes or historical cost basis;

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our ability to generate cash sufficient to pay interest on our indebtedness and to make distributions to our partners;

•

our operating performance and return on invested capital compared to those of other companies in the retail distribution of refined petroleum products business, without regard to financing methods and capital structure; and

•

the viability of acquisitions and capital expenditure projects and the overall rates of return of alternative investment opportunities.

The method of calculating Adjusted EBITDA may not be consistent with that of other companies and each of EBITDA and Adjusted EBITDA has its limitations as an analytical tool, should not be considered in isolation and should be viewed in conjunction with measurements that are computed in accordance with GAAP. Some of the limitations of EBITDA and Adjusted EBITDA are:

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EBITDA and Adjusted EBITDA do not reflect our cash used for capital expenditures;

•

Although depreciation and amortization are non-cash charges, the assets being depreciated or amortized often will have to be replaced and EBITDA and Adjusted EBITDA do not reflect the cash requirements for such replacements;

•

EBITDA and Adjusted EBITDA do not reflect changes in, or cash requirements for, our working capital requirements;

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EBITDA and Adjusted EBITDA do not reflect the cash necessary to make payments of interest or principal on our indebtedness; and

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EBITDA and Adjusted EBITDA do not reflect the cash required to pay taxes.

Customer Attrition

We measure net customer attrition on an ongoing basis for our full service residential and commercial home heating oil and propane customers. Since October 1, 2010, we have included propane customers in this calculation as several of our acquisitions since that date have included propane operations. Net customer attrition is the difference between gross customer losses and customers added through marketing efforts. Customers added through acquisitions are not included in the calculation of gross customer gains. However, additional customers that are obtained through marketing efforts at newly acquired businesses are included in these calculations. Gross customer losses are the result of a number of factors, including price competition, move-outs, service issues, credit losses and conversion to natural gas. When a customer moves out of an existing home, we count the “move out” as a loss and, if we are successful in signing up the new homeowner, the “move in” is treated as a gain.

Gross customer gains and gross customer losses


	Fiscal Year Ended
	2012							2011							2010 (a)
					Net			Gross Customer				Net			Gross Customer				Net
	Gains		Losses		Attrition			Gains		Losses		Attrition			Gains		Losses		Attrition
First Quarter		25,700		26,600		(900	)		21,900		24,100		(2,200	)		19,000		21,600		(2,600	)
Second Quarter									11,800		17,200		(5,400	)		11,000		14,200		(3,200	)
Third Quarter									6,000		11,400		(5,400	)		5,300		12,600		(7,300	)
Fourth Quarter									15,300		17,100		(1,800	)		10,100		16,800		(6,700	)

Total									55,000		69,800		(14,800	)		45,400		65,200		(19,800	)

Net customer attrition as a percentage of the home heating oil customer base


	Fiscal Year Ended
	2012									2011									2010 (a)
							Net			Gross Customer						Net			Gross Customer						Net
	Gains			Losses			Attrition			Gains			Losses			Attrition			Gains			Losses			Attrition
First Quarter		6.2	%		6.4	%		(0.2	%)		5.3	%		5.8	%		(0.5	%)		4.8	%		5.5	%		(0.7	%)
Second Quarter											2.8	%		4.1	%		(1.3	%)		2.8	%		3.6	%		(0.8	%)
Third Quarter											1.5	%		2.8	%		(1.3	%)		1.4	%		3.2	%		(1.8	%)
Fourth Quarter											3.6	%		4.0	%		(0.4	%)		2.6	%		4.3	%		(1.7	%)

Total											13.2	%		16.7	%		(3.5	%)		11.6	%		16.6	%		(5.0	%)

(a)	Prior to October 1, 2010, we measured only home heating oil net customer attrition.

During the first quarter of fiscal 2012, we lost 900 accounts (net), or 0.2% of our home heating oil and propane customer base, 1,300 accounts less than the first quarter of fiscal 2011 in which we lost 2,200 accounts (net), or 0.5% of our home heating oil and propane customer base. The improvement was largely due to the success of our propane marketing initiatives as we added an additional 700 propane accounts, (net) during the first quarter of fiscal 2012 when compared to the first quarter of fiscal 2011.

During the three months ended December 31, 2011, we lost 0.6% of our home heating oil accounts to natural gas compared to losses of 0.4% for the three months ended December 31, 2010 and 0.4% for the three months ended December 31, 2009. We believe that conversions to natural gas have increased and may continue to do so as natural gas has become significantly less expensive than home heating oil on an equivalent BTU basis.

Consolidated Results of Operations

The following is a discussion of the consolidated results of operations of the Partnership and its subsidiaries, and should be read in conjunction with the historical Financial and Operating Data and Notes thereto included elsewhere in this Quarterly Report.

Three Months Ended December 31, 2011

Compared to the Three Months Ended December 31, 2010

Volume

For the three months ended December 31, 2011 retail volume of home heating oil and propane decreased by 21.6 million gallons, or 19.1%, to 91.1 million gallons, compared to 112.7 million gallons for the three months ended December 31, 2010. For those locations that the Partnership operated in both periods, which we sometimes refer to as the “base business” (i.e., excluding acquisitions), temperatures (measured on a degree day basis) for the three months ended December 31, 2011 were 22.2% warmer than the three months ended December 31, 2010 and 19.9% warmer than normal, as reported by the National Oceanic and Atmospheric Administration (“NOAA”). For the twelve months ended December 31, 2011, net customer attrition was 3.3%. Due to the significant increase in the price per gallon of home heating oil and propane over the last several years, we believe that customers are consuming less given similar temperatures than in prior periods. In addition, the timing of certain deliveries resulted in an increase in home heating oil and propane sold during the three months ended December 31, 2011 compared to the three months ended December 31, 2010. An analysis of the change in the retail volume of home heating oil and propane, which is based on management’s estimates, sampling and other mathematical calculations, is found below:


(in millions of gallons)	Heating Oil and Propane
Volume - Three months ended December 31, 2010		112.7
Acquisitions		3.9
Impact of warmer temperatures		(23.9	)
Net customer attrition		(4.6	)
Other		3.0

Change		(21.6	)


Volume - Three months ended December 31, 2011		91.1

Volume of other petroleum products increased by 2.8 million gallons, or 24.1%, to 14.3 million gallons for the three months ended December 31, 2011, compared to 11.5 million gallons for the three months ended December 31, 2010, as the additional volume from acquisitions more than offset a decline in other petroleum products primarily due to the warmer temperatures.

The percentage of home heating oil volume sold to residential variable price customers decreased to 43.0% of total home heating oil volume sales for the three months ended December 31, 2011, compared to 44.1% for the three months ended December 31, 2010. Accordingly, the percentage of home heating oil volume sold to residential price-protected customers increased to 43.7% for the three months ended December 31, 2011, compared to 43.0% for the three months ended December 31, 2010. For the three months ended December 31, 2011, sales to commercial/industrial customers represented 13.3% of total home heating oil volume sales, compared to 12.9% for the three months ended December 31, 2010.

Product Sales

For the three months ended December 31, 2011, product sales increased $1.7 million, or 0.4%, to $406.7 million, compared to $405.0 million for the three months ended December 31, 2010, as the decline in total volume was more than offset by higher product selling prices. Selling prices increased in response to higher per gallon wholesale product costs of $0.5752 per gallon.

Installation and Service Sales

For the three months ended December 31, 2011, installation and service sales increased $0.3 million, or 0.5%, to $54.8 million, compared to $54.5 million for the three months ended December 31, 2010, as the additional revenue from acquisitions of $1.3 million was reduced by a decline in the base business of $1.0 million. Installation revenue in the base business declined by $0.8 million or 3.7% largely due to a reduction in the customer base.

Cost of Product

For the three months ended December 31, 2011, cost of product increased $15.0 million, or 5.0%, to $316.7 million, compared to $301.7 million for the three months ended December 31, 2010, as the impact of higher per gallon wholesale product costs of $0.5752, or 23.7%, more than offset the reduction in volume.

Gross Profit - Product

The table below calculates the Partnership’s per gallon margins and reconciles product gross profit for home heating oil and propane and other petroleum products. We believe the change in home heating oil and propane margins should be evaluated before the effects of increases or decreases in the fair value of derivative instruments, as we believe that realized per gallon margins should not include the impact of non-cash changes in the market value of hedges before the settlement of the underlying transaction. On that basis, home heating oil and propane margins for the three months ended December 31, 2011 increased by $0.0579 per gallon, or 6.5%, to $0.9504 per gallon, from $0.8925 per gallon during the three months ended December 31, 2010. Product sales and cost of product include home heating oil, propane, other petroleum products and liquidated damages billings.


	Three Months Ended
	December 31, 2011				December 31, 2010
Home Heating Oil and Propane	Amount (in millions)		Per Gallon		Amount (in millions)		Per Gallon
Volume		91.1				112.7

Sales	$	359.1	$	3.9423	$	373.8	$	3.3178
Cost		272.6		2.9919		273.2		2.4253


Gross Profit	$	86.5	$	0.9504	$	100.6	$	0.8925


Other Petroleum Products	Amount (in millions)		Per Gallon		Amount (in millions)		Per Gallon
Volume		14.3				11.5

Sales	$	47.6	$	3.3218	$	31.2	$	2.7031
Cost		44.1		3.0829		28.4		2.4651


Gross Profit	$	3.5	$	0.2389	$	2.7	$	0.2381


Total Product	Amount (in millions)				Amount (in millions)
Sales	$	406.7			$	405.0
Cost		316.7				301.7


Gross Profit	$	90.0			$	103.3

For the three months ended December 31, 2011, total product gross profit decreased by $13.3 million to $90.0 million, compared to $103.3 million for the three months ended December 31, 2010, as the impact of higher home heating oil and propane margins ($5.3 million) and the additional gross profit from other petroleum products ($0.7 million) was more than offset by a reduction in gross profit resulting from lower home heating oil and propane volume ($19.3 million).

Cost of Installations and Service

For the three months ended December 31, 2011, cost of installation and service decreased by $0.3 million, or 0.5%, to $52.3 million, compared to $52.6 million for the three months ended December 31, 2010, as a $1.2 million increase due to fiscal 2012 and fiscal 2011 acquisitions was offset by a $1.5 million reduction in service costs and installation costs in our base business in response to a decline in the base business customer base and the impact of warmer weather.

Installation costs decreased by $0.3 million to $18.2 million, or 82.9% of installation sales, during the three months ended December 31, 2011, versus $18.5 million, or 82.8% of installation sales during the three months ended December 31, 2010. Service expenses were unchanged at $34.1 million for the first quarter of fiscal 2012 and fiscal 2011, or 104.1% and 106.0%, respectively, of service sales for the three months ended December 31, 2011 and the three months ended December 31, 2010. We achieved a combined profit from service and installation of $2.5 million for the three months ended December 31, 2011, compared to a combined profit of $1.9 million for the three months ended December 31, 2010. Management views the service and installation department on a combined basis because many overhead functions and direct expenses such as service technician time cannot be separated or precisely allocated to either service or installation billings.

(Increase) Decrease in the Fair Value of Derivative Instruments

During the three months ended December 31, 2011, the change in the fair value of derivative instruments resulted in a $7.1 million charge due to the expiration of certain hedged positions (a $0.5 million credit), and a decrease in market value for unexpired hedges (a $7.6 million charge).

During the three months ended December 31, 2010, the change in the fair value of derivative instruments resulted in a $13.9 million credit due to the expiration of certain hedged positions (a $4.0 million credit) and an increase in market value for unexpired hedges (a $9.9 million credit).

Delivery and Branch Expenses

For the three months ended December 31, 2011, delivery and branch expenses increased $1.8 million, or 2.7%, to $67.8 million, compared to $66.0 million for the three months ended December 31, 2010. Acquisitions accounted for $2.5 million of the higher delivery and branch expenses. In the base business, delivery and branch expenses decreased by $0.7 million, or 1.1%, compared to a 22.6% decline in home heating oil and propane volume in the base business.

On a cents per gallon basis, delivery and branch expenses for the three months ended December 31, 2011 increased 11.3 cents, or 20.7%, to 65.9 cents, compared to 54.6 cents for the three months ended December 31, 2010 due to the fixed nature of certain operating expenses that could not be adjusted in the near term due to the weather related decline in home heating oil and propane volume. In addition, an increase in vehicle fuel expense, delivery inefficiencies arising from the abnormally warm weather and additional sales and marketing expenses to support a higher level of account gains negatively impacted the quarter to quarter comparison.

Depreciation and Amortization

For the three months ended December 31, 2011, depreciation and amortization expenses decreased by $1.0 million, or 20.7% to $3.6 million, compared to $4.6 million for the three months ended December 31, 2010.

Amortization expense relating to fiscal 2001 and fiscal 2004 acquisitions with lives of ten years and seven years respectively, decreased by $1.3 million, as they became fully amortized in fiscal 2011. This decrease was partially offset by an increase of $0.2 million relating to fiscal 2012 and fiscal 2011 acquisitions with ten year lives.

General and Administrative Expenses

For the three months ended December 31, 2011, general and administrative expenses increased $0.5 million to $5.4 million, or 9.0%, from $4.9 million for the three months ended December 31, 2010. This increase was due to higher acquisition related expenses of $0.5 million.

Interest Expense

For the three months ended December 31, 2011, interest expense decreased by $0.7 million, or 18.2%, to $3.5 million, compared to $4.2 million during the three months ended December 31, 2010. Average long-term debt decreased by $10.8 million, and the weighted average long-term borrowing rate decreased from 9.62% to 8.87%, which resulted in a decrease in interest expense of $0.5 million. In November 2010, the Partnership issued $125 million of 8.875% Senior Notes due 2017 and in December 2010 repaid $82.5 million of 10.25% Senior Notes due 2013.

During the three months ended December 31, 2011, the Partnership borrowed an average of $6.0 million under its revolving credit facility, or $5.7 million higher than the three months ended December 31, 2010, which resulted in a negligible increase in interest expense as the interest rate on these borrowings declined from 5.8% to 4.30%. In addition, bank fees were lower by $0.4 million due to lower rates on letters of credit and lower unused commitment fees.

Interest Income

For the three months ended December 31, 2011, interest income increased $0.2 million to $0.7 million, compared to $0.5 million for the three months ended December 31, 2010, due to higher finance charge income from acquisitions and higher past due accounts receivable balances.

Amortization of Debt Issuance Costs

For the three months ended December 31, 2011, amortization of debt issuance costs decreased by $0.4 million to $0.3 million, compared to $0.7 million in the three months ended December 31, 2010. This reduction is due to the extension in June 2011 of the Partnership’s revolving credit facility termination date from July 2012 to June 2016.

Loss on Redemption of Debt

In November 2010, the Partnership issued $125.0 million of Senior Notes due 2017. The Notes accrue interest at a rate of 8.875% and were priced at 99.350% for total gross proceeds of $124.2 million. A portion of the proceeds were used to redeem all of the remaining $82.5 million in face value of our 10.25% Senior Notes due 2013, at an average price of $101.70 per $100 of principal plus accrued interest, with the remainder used for general Partnership purposes. The Partnership recorded a loss of $1.7 million for this transaction.

Income Tax Expense

For the three months ended December 31, 2011, income tax expense decreased by $14.4 million, to $2.6 million, from $17.0 million for the three months ended December 31, 2010, due to a decline in pretax income of $32.0 million. The Partnership’s effective tax rate rose to 47.5% for the three months ended December 31, 2011 from 45.3% for the three months ended December 31, 2010. The increased rate is due to the impact of certain non-deductible Partnership expenses and discrete tax items being divided by a much lower pretax income amount.

Net Income (Loss)

For the three months ended December 31, 2011, net income decreased $17.7 million to $2.9 million, from $20.6 million for the three months ended December 31, 2010, as the decrease in pretax income of $32.0 million exceeded the decrease in income tax expense of $14.4 million.

Adjusted EBITDA

For the three months ended December 31, 2011, Adjusted EBITDA decreased by $15.0 million, or 43.7%, to $19.3 million as the impact of warmer temperatures of 22.2% and net customer attrition more than offset an increase in Adjusted EBITDA provided by fiscal 2012 and 2011 acquisitions and an increase in home heating oil and propane per gallon gross profit margins.

EBITDA and Adjusted EBITDA should not be considered as an alternative to net income (as an indicator of operating performance) or as an alternative to cash flow (as a measure of liquidity or ability to service debt obligations), but provides additional information for evaluating our ability to make the Minimum Quarterly Distribution.

EBITDA and Adjusted EBITDA are calculated as follows:


	Three Months Ended December 31,
(in thousands)	2011			2010

Net income	$	2,931		$	20,558
Plus:
Income tax expense		2,652			17,011
Amortization of debt issuance cost		274			694
Interest expense, net		2,724			3,688
Depreciation and amortization		3,629			4,577

EBITDA from continuing operations (a)		12,210			46,528

(Increase) / decrease in the fair value of derivative instruments		7,118			(13,906	)
Loss on redemption of debt		—			1,700

Adjusted EBITDA (a)		19,328			34,322

Add / (subtract)
Income tax benefit		(2,652	)		(17,011	)
Interest expense, net		(2,724	)		(3,688	)
Provision for losses on accounts receivable		1,450			2,648
Increase in accounts receivables		(79,111	)		(115,161	)
Increase in inventories		(18,883	)		(10,324	)
Decrease in customer credit balances		(5,316	)		(23,134	)
Change in deferred taxes		1,154			14,980
Change in other operating assets and liabilities		11,989			28,658

Net cash used in operating activities	$	(74,765	)	$	(88,710	)



Net cash used in investing activities	$	(26,898	)	$	(3,182	)



Net cash provided by financing activities	$	28,794		$	44,634

(a)

•

our compliance with certain financial covenants included in our debt agreements;

•

our financial performance without regard to financing methods, capital structure, income taxes or historical cost basis;

•

our ability to generate cash sufficient to pay interest on our indebtedness and to make distributions to our partners;

•

the viability of acquisitions and capital expenditure projects and the overall rates of return of alternative investment opportunities.

•

EBITDA and Adjusted EBITDA do not reflect our cash used for capital expenditures

•

EBITDA and Adjusted EBITDA do not reflect changes in, or cash requirements for, our working capital requirements;

•

EBITDA and Adjusted EBITDA do not reflect the cash necessary to make payments of interest or principal on our indebtedness; and

•

EBITDA and Adjusted EBITDA do not reflect the cash required to pay taxes.

DISCUSSION OF CASH FLOWS

We use the indirect method to prepare our Consolidated Statements of Cash Flows. Under this method, we reconcile net income to cash flows provided by operating activities by adjusting net income for those items that impact net income but may not result in actual cash receipts or payment during the period.

Operating Activities

Due to the seasonal nature of our business, cash is generally used in operations during the winter (our first and second fiscal quarters) as we require additional working capital to support the high volume of sales during this period, and cash is generally provided by operating activities during the spring and summer (our third and fourth quarters) when customer payments exceed deliveries.

During the three months ended December 31, 2011, cash used in operating activities decreased by $13.9 million to $74.8 million, compared to $88.7 million during the three months ended December 31, 2010, as a reduction in cash generated from operations of $14.7 million, an increase in cash needs for inventory of $8.6 million, a reduction in accounts payable of $9.6 million and a $11.2 million change in other liabilities was offset by a decline in cash needs for accounts receivable of $36.1 million and greater receipts from our customers on a budget payment plan of $17.8 million. While higher product costs drove the increase in inventory values, the warm weather more than offset the impact of higher selling prices and resulted in a lower cash need for accounts receivable. Days sales outstanding as of December 31, 2011 were 37 days compared to 38 days at December 31, 2010 and 36 days at December 31, 2009. The difference in weather between the two quarters favorably impacted receivables due from our budget payment plan customers, as sales for the quarter ended December 31, 2011 were less than expected while sales for the three months ended December 31, 2010 were greater than anticipated. Home heating oil and propane purchases were less in December 2011 than in December 2010 due to the warm weather and the corresponding accounts payable to trade creditors also declined. A decline in the expected cash payments on derivative instruments and the timing of cash payments for interest expense led to a reduction in other liabilities.

Investing Activities

Our capital expenditures for the three months ended December 31, 2011 totaled $1.3 million, as we invested in computer hardware and software ($0.3 million), refurbished certain physical plants ($0.5 million), expanded our propane operations ($0.4 million) and made additions to our fleet and other equipment ($0.1 million). We also completed three acquisitions for $25.9 million and allocated $16.1 million of the gross purchase price to intangible assets (including $6.2 million to goodwill), $5.8 million to fixed assets and $4.0 to working capital.

Our capital expenditures for the three months ended December 31, 2010 totaled $1.6 million, as we invested in computer hardware and software ($0.5 million), refurbished certain physical plants ($0.2 million), expanded our propane operations ($0.1 million) and made additions to our fleet and other equipment ($0.8 million). We also completed one acquisition for $1.6 million and allocated $0.3 million of the gross purchase price to intangible assets $0.7 million to fixed assets, $0.3 million to other long-term assets and $0.3 to working capital.

Financing Activities

During the three months ended December 31, 2011, we borrowed $46.8 million under our credit facility, paid distributions to our unit holders of $5.1 million, including $0.06 million paid to our General Partner as incentive distributions (as provided in our Partnership Agreement) and repurchased 2.4 million units for $12.6 million in connection with our unit repurchase plan.

During the three months ending December 31, 2010, we sold $125 million of 8.875% Senior Notes due 2017 at a price of 99.350%. A portion of the net proceeds were used on December 20, 2010, to repurchase $82.5 million in face value of 10.25% Senior Notes due February 2013. After paying expenses of $3.8 million and a call premium of $1.4 million, our cash balance increased by $36.5 million, which was utilized for General Partnership purposes. Also during the three months ended December 31, 2010, we paid distributions of $4.9 million, including $0.04 million paid to our General Partner as incentive distributions (as provided for in our Partnership Agreement).

FINANCING AND SOURCES OF LIQUIDITY

Liquidity and Capital Resources

Our primary liquidity needs are to fund our working capital requirements, capital expenditures, pay distributions, acquisitions and unit repurchases. Our ability to satisfy our obligations depends on our future performance, which will be subject to prevailing economic, financial, business and weather conditions, the ability to pass on the full impact of high wholesale heating oil prices to customers, the effects of high net customer attrition, conservation and other factors, most of which are beyond our control. Capital requirements, at least in the near term, are expected to be provided by cash flows from operating activities, cash on hand as of December 31, 2011, or a combination thereof. To the extent future capital requirements exceed cash on hand plus cash flows from operating activities, we anticipate that working capital will be financed by our revolving credit facility, as discussed below, and repaid from subsequent seasonal reductions in inventory and accounts receivable. If we require additional capital, we may seek to offer and sell debt or equity securities under our $250 million shelf registration statement. For the four months ended January 31, 2012, temperatures were 23.0% warmer than the comparable period of fiscal 2011 and 19.8% warmer than normal. The impact of these abnormal temperatures will adversely impact our liquidity, Adjusted EBITDA, net income (loss) in fiscal 2012 and possibly our ability to raise additional capital, fund our future cash needs, and our ability to pay distributions and repurchase units. (See Item 1A Risk Factors)

In June 2011 and November 2011, we amended and restated our asset based revolving facility, under which our subsidiary, Petroleum Heat and Power Co., is the borrower and we are an additional loan party, extending the maturity date from July 2012 to June 2016. The amended facility provides us with the ability to borrow up to $250 million ($350 million during the heating season from November through April of each year) for working capital purposes (subject to certain borrowing base limitations and coverage ratios), including the issuance of up to $100 million in letters of credit. We can increase the facility size by $100 million without the consent of the bank group. However, the bank group is not obligated to fund the $100 million increase. If the bank group elects not to fund the increase, we can add additional lenders to the group, with the consent of the Agent, which shall not be unreasonably withheld. Obligations under the revolving credit facility are guaranteed by us and our subsidiaries and secured by liens on substantially all of our assets, including accounts receivable, inventory, general intangibles, real property, fixtures and equipment. As of December 31, 2011, $46.3 million in letters of credit were outstanding, of which $46.0 million are for current and future insurance reserves and bonds and $0.3 million are for seasonal inventory purchases and other working capital purposes.

Under the terms of the revolving credit facility, we must maintain at all times either availability (borrowing base less amounts borrowed and letters of credit issued) of 12.5% of the maximum facility size or a fixed charge coverage ratio of not less than 1.1, which is calculated based upon Adjusted EBITDA. As of December 31, 2011, availability, as defined in the amended and restated revolving credit facility agreement, was $128.1 million and we were in compliance with the fixed charge coverage ratio. Any failure to comply with these covenants could have a material adverse effect on our liquidity and results of operations.

The Partnership’s scheduled interest payments for the remainder of fiscal 2012 are $5.5 million on its Senior Notes. Maintenance capital expenditures for fixed assets are estimated to be approximately $4.0 to $4.5 million, excluding the capital requirements for leased fleet for the remainder of fiscal 2012. In addition, we plan to invest an estimated $1.0 to $2.0 million in our propane operations for fleet and tank purchases. Based on the funding levels required by the Pension Protection Act of 2006, and certain

actuarial assumptions, we estimate that the Partnership will be required to make minimum cash contributions to fund its frozen defined benefit pension obligations for fiscal 2012 of $2.7 million and $12.0 million for fiscal 2013 - 2016. At the present time we anticipate paying distributions during the last three quarters of fiscal 2012 at the current level of $0.0775 per unit, for an aggregate of approximately $14.2 million to common unit holders, $0.2 million to our General Partner (including incentive distributions) and $0.1 million to management pursuant to the management incentive compensation plan (as provided in our Partnership Agreement). We continue to seek strategic acquisitions and we may continue to repurchase common units as authorized under our unit repurchase plan, or otherwise approved by our Board of Directors.

In January 2012, the Partnership, as authorized under its Plan II common unit repurchase program, repurchased 1.2 million common units for an aggregate cost of $5.6 million (including repurchase costs) and at an average price paid per unit of $4.63. As of January 31, 2012, 0.3 million common units remains to be repurchased under this program. (See Item 1A Risk Factors for a discussion of the impact of the warmer than normal temperatures that the Partnership has experienced so far during the fiscal 2012 heating season on its ability to pay distributions and repurchase units.)

Partnership Distribution Provisions

On January 19, 2012, we declared a quarterly distribution of $0.0775 per unit, or $0.31 per unit on an annualized basis, on all common units in respect of the first quarter of fiscal 2012 payable on February 7, 2012 to holders of record on January 30, 2012. In accordance with our Partnership Agreement, the amount of distributions in excess of the minimum quarterly distribution of $0.0675, are distributed 90% to the holders of common units and 10% to the holders of the General Partner units (until certain distribution levels are met), subject to the management incentive compensation plan. As a result, $4.8 million was paid to the common unit holders, $0.06 million was paid to the General Partner and $0.03 million was paid to management pursuant to the management incentive compensation plan.

Contractual Obligations and Off-Balance Sheet Arrangements

There has been no material change to Contractual Obligations and Off-Balance Sheet Arrangements since September 30, 2011, and therefore, the table has not been included in this Form 10-Q.

Recent Accounting Pronouncements

The following new accounting standards are currently being evaluated by the Partnership, and are more fully described in Note 3. Summary of Significant Accounting Policies - Recent Accounting Pronouncements, of the consolidated financial statements:

•

Accounting Standards Update (“ASU”) No. 2011-04, Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. generally accepted accounting principles (“U.S. GAAP”) and the International Financial Reporting Standards (“IFRS”).

•

ASU No. 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income.

•

ASU No. 2011-08, Intangibles-Goodwill and Other (Topic 350): Testing Goodwill for Impairment.

•

ASU No. 2011-09, Compensation—Retirement Benefits—Multiemployer Plans (Subtopic 715-80): Disclosures about an Employer’s Participation in a Multiemployer Plan.

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

We are exposed to interest rate risk primarily through our bank credit facilities. We utilize these borrowings to meet our working capital needs.

At December 31, 2011, we had outstanding borrowings totaling $171.1 million (excluding discounts), of which approximately $46.8 million is subject to variable interest rates under our revolving credit facility. In the event that interest rates associated with this facility were to increase 100 basis points, the impact on future cash flows would be a decrease of $0.5 million.

We also use derivative financial instruments to manage our exposure to market risk related to changes in the current and future market price of home heating oil. The value of market sensitive derivative instruments is subject to change as a result of movements in market prices. Sensitivity analysis is a technique used to evaluate the impact of hypothetical market value changes. Based on a hypothetical ten percent increase in the cost of product at December 31, 2011, the potential impact on our hedging activity would be to increase the fair market value of these outstanding derivatives by $9.2 million to a fair market value of $1.3 million; and conversely a hypothetical ten percent decrease in the cost of product would decrease the fair market value of these outstanding derivatives by $2.5 million to a fair market value of $(10.3) million.

Item 4.

Controls and Procedures

a) Evaluation of disclosure controls and procedures.

The General Partner’s principal executive officer and its principal financial officer evaluated the effectiveness of the Partnership’s disclosure controls and procedures (as that term is defined in Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended) as of December 31, 2011. Based on that evaluation, such principal executive officer and principal financial officer concluded that the Partnership’s disclosure controls and procedures were effective as of December 31, 2011 at the reasonable level of assurance. For purposes of Rule 13a-15(e), the term disclosure controls and procedures means controls and other procedures of an issuer that are designed to ensure that information required to be disclosed by the issuer in the reports that it files or submits under the Act (15 U.S.C. 78a et seq.) is recorded, processed, summarized and reported, within the time periods specified in the Commission’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Act is accumulated and communicated to the issuer’s management, including its principal executive and principal financial officer, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

b) Change in Internal Control over Financial Reporting.

No change in the Partnership’s internal control over financial reporting occurred during the Partnership’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect the Partnership’s internal control over financial reporting.

c) The General Partner and the Partnership believe that a controls system, no matter how well designed and operated, cannot provide absolute assurance that the objectives of the controls system are met, and no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within a Partnership have been detected. Therefore, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Our disclosure controls and procedures are designed to provide such reasonable assurances of achieving our desired control objectives, and the principal executive officer and principal financial officer of our general partner have concluded, as of December 31, 2011, that our disclosure controls and procedures were effective in achieving that level of reasonable assurance.

PART II OTHER INFORMATION

Item 1

Legal Proceedings

In the opinion of management, we are not a party to any litigation, which individually or in the aggregate could reasonably be expected to have a material adverse effect on our results of operations, financial position or liquidity.

Item 1A

Risk Factors

In addition to the other information set forth in this Report, investors should carefully review and consider the information regarding certain factors which could materially affect our business, results of operations, financial condition and cash flows set forth below and in Part I Item 1A. “Risk Factors” in our Fiscal 2011 Form 10-K. We may disclose changes to such factors or disclose additional factors from time to time in our future filings with the SEC.

We are experiencing warmer than normal weather conditions in the fiscal 2012 heating season, which will have an adverse effect on our fiscal 2012 results of operations and our financial condition.

Temperatures in our geographic areas of operations for our base business for the three months ended December 31, 2011 were 22.2% warmer than the three months ended December 31, 2010 and 19.9% warmer than normal, as reported by the National Oceanic and Atmospheric Administration (“NOAA”). For the three months ended December 31, 2011, our retail volume of home heating oil and propane decreased by 21.6 million gallons, or 19.1%, to 91.1 million gallons, compared to 112.7 million gallons for the three months ended December 31, 2010. We estimate that the impact of warmer temperatures reduced our volume during the fiscal 2012 first quarter by approximately 23.9 million gallons, which was only partially offset by additional volume from acquisitions.

In addition, temperatures for January 2012 were 15.6% warmer than normal and 21.5% warmer than January 2011. For January 2012, home heating oil and propane volume decreased by 18.3 million gallons, or 25.2% to 54.4 million gallons, compared to 72.7 million gallons for January 2011, as the impact of warmer temperatures, net customer attrition and conservation more than offset the additional volume provided from acquisitions.

To partially mitigate the adverse effect of warm weather on our cash flows, we have used weather hedging contracts for a number of years. For the fiscal 2012 heating season, we have entered into a weather hedge contract with Renaissance Trading Ltd. under which we are entitled to receive a payment of $35,000 per heating degree-day shortfall, when the total number of heating degree-days in the period covered is less than 92.5% of the ten year average (the “Payment Threshold”). The hedge covers the period from November 1, 2011 through March 31, 2012 taken as a whole, and has a maximum payout of $12.5 million. While temperatures for November 1 to December 31, 2011 were warmer than the ten year average, the Partnership did not accrue any benefit from this weather contract for the first quarter of fiscal 2012 as the Payment Threshold had not been met as of the end of the first quarter. Temperatures for January 2012 were 13.9% warmer than the ten year average and 21.5% warmer than January 2011 which caused us to meet the Payment Threshold under the weather hedge contract as of January 31, 2012. Assuming that temperatures are equal to the ten year average during the remainder of the second fiscal quarter, we currently estimate that we will receive $3.3 million under the weather hedge contract. However, if temperatures in February and March 2012 are colder than the ten year average, then the expected payment under the weather hedge contract will be reduced or eliminated.

The impact of the warmer than normal weather conditions in the fiscal 2012 heating season will adversely affect our liquidity, Adjusted EBITDA and net income (loss) in fiscal 2012, which could adversely affect our ability to raise additional capital to fund our future cash needs and to make distributions and repurchase units. In addition, if the warm weather continues into February and March 2012, we may need to obtain a modification of certain covenants in our revolving credit facility agreement in order to continue to pay distributions and repurchase units.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

See Note 2. to the Consolidated Financial Statements for information concerning the Partnership’s repurchase of common units in the three months ended December 31, 2011.

Item 6.

Exhibits

(a)	Exhibits Included Within:


31.1		Certification of Chief Executive Officer, Star Gas Partners, L.P., pursuant to Rule 13a-14(a)/15d-14(a).

31.2		Certification of Chief Financial Officer, Star Gas Partners, L.P., pursuant to Rule 13a-14(a)/15d-14(a).

32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101		The following materials from the Star Gas Partners, L.P. Quarterly Report on Form 10-Q for the quarter ended December 31, 2011 formatted in Extensible Business Reporting Language (XBRL): (i) the Condensed Consolidated Statements of Operations, (ii) the Condensed Consolidated Balance Sheets, (iii) the Condensed Consolidated Statements of Cash Flows and (iv) related notes.

#101.INS		XBRL Instance Document.

#101.SCH		XBRL Taxonomy Extension Schema Document.

#101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document.

#101.LAB		XBRL Taxonomy Extension Label Linkbase Document.

#101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document.

#101.DEF		XBRL Taxonomy Extension Definition Linkbase Document.

#		Filed herewith. In accordance with Rule 406T of Regulation S-T, these interactive data files are deemed “not filed” for purposes of section 18 of the Exchange Act, and otherwise are not subject to liability under that section.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on its behalf of the undersigned thereunto duly authorized:

Star Gas Partners, L.P.

(Registrant)

By: Kestrel Heat LLC AS GENERAL PARTNER


Signature	Title	Date

/S/ RICHARD F. AMBURY	Executive Vice President, Chief	February 7, 2012
Richard F. Ambury	Financial Officer, Treasurer and Secretary
	Kestrel Heat LLC
	(Principal Financial Officer)

Signature	Title	Date

/S/ RICHARD G. OAKLEY	Vice President - Controller	February 7, 2012
Richard G. Oakley	Kestrel Heat LLC
	(Principal Accounting Officer)

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