SEC Filing - Star Group, L.P.

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

View:

Download DOC

Download PDF

Download XLS

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 March 31, 2012

¨	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 April 30, 2012, the registrant had 61,024,306 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 March 31, 2012 (unaudited) and September 30, 2011		3

Condensed Consolidated Statements of Operations (unaudited) for the three and six months ended March 31, 2012 and March 31, 2011		4

Condensed Consolidated Statement of Partners’ Capital and Comprehensive Income for the six months ended March 31, 2012 (unaudited)		5

Condensed Consolidated Statements of Cash Flows (unaudited) for the six months ended March 31, 2012 and March 31, 2011		6

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

Item 2—Management’s Discussion and Analysis of Financial Condition and Results of Operations		20-37

Item 3—Quantitative and Qualitative Disclosures About Market Risk		37

Item 4—Controls and Procedures		37

Part II Other Information:

Item 1—Legal Proceedings		38

Item 1A—Risk Factors		38

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)	March 31, 2012			September 30, 2011
	(unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	25,053		$	86,789
Receivables, net of allowance of $11,013 and $9,530 respectively		204,939			92,967
Inventories		45,308			80,536
Fair asset value of derivative instruments		4,752			3,674
Weather hedge contract receivable		12,500			—
Current deferred tax asset, net		3,340			13,155
Prepaid expenses and other current assets		19,051			22,296

Total current assets		314,943			299,417


Property and equipment, net		52,040			47,131
Goodwill		205,469			199,296
Intangibles, net		59,098			52,348
Long-term deferred tax asset, net		3,970			17,646
Deferred charges and other assets, net		9,996			10,291

Total assets	$	645,516		$	626,129


LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Accounts payable	$	14,423		$	18,569
Revolving credit facility borrowings		32,403			—
Fair liability value of derivative instruments		—			3,322
Accrued expenses and other current liabilities		86,241			76,428
Unearned service contract revenue		44,538			40,903
Customer credit balances		35,368			67,214

Total current liabilities		212,973			206,436


Long-term debt		124,309			124,263
Other long-term liabilities		20,882			22,797

Partners’ capital
Common unitholders		313,703			299,913
General partner		301			187
Accumulated other comprehensive loss, net of taxes		(26,652	)		(27,467	)

Total partners’ capital		287,352			272,633

Total liabilities and partners’ capital	$	645,516		$	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 March 31,						Six Months Ended March 31,
(in thousands, except per unit data - unaudited)	2012			2011			2012			2011
Sales:
Product	$	584,208		$	686,452		$	990,877		$	1,091,420
Installations and service		45,384			45,413			100,189			99,946

Total sales		629,592			731,865			1,091,066			1,191,366
Cost and expenses:
Cost of product		459,224			519,154			775,897			820,826
Cost of installations and service		44,374			46,075			96,725			98,697
(Increase) decrease in the fair value of derivative instruments		(16,981	)		(13,261	)		(9,863	)		(27,167	)
Delivery and branch expenses		61,713			81,975			129,470			147,936
Depreciation and amortization expenses		3,829			4,699			7,458			9,276
General and administrative expenses		4,554			5,264			9,919			10,188

Operating income		72,879			87,959			81,460			131,610
Interest expense		(3,829	)		(4,319	)		(7,281	)		(8,539	)
Interest income		1,208			1,241			1,936			1,773
Amortization of debt issuance costs		(385	)		(732	)		(659	)		(1,426	)
Loss on redemption of debt		—			—			—			(1,700	)

Income before income taxes		69,873			84,149			75,456			121,718
Income tax expense		29,391			35,468			32,043			52,479

Net income	$	40,482		$	48,681		$	43,413		$	69,239

General Partner’s interest in net income		213			236			228			335

Limited Partners’ interest in net income	$	40,269		$	48,445		$	43,185		$	68,904


Basic and Diluted income per Limited Partner Unit (1)	$	0.55		$	0.61		$	0.59		$	0.86


Weighted average number of Limited Partner units outstanding: Basic and Diluted		61,474			67,078			62,839			67,078

(1)	See Note 3 Summary of Significant Accounting Policies - Net Income (Loss) 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		—			—		43,185			228			—			43,413
Unrealized gain on pension plan obligation		—			—		—			—			1,376			1,376
Tax effect of unrealized gain on pension plan		—			—		—			—			(561	)		(561	)

Total comprehensive income		—			—		43,185			228			815			44,228
Distributions		—			—		(9,840	)		(114	)		—			(9,954	)
Retirement of units (1)		(3,946	)		—		(19,555	)		—			—			(19,555	)

Balance as of March 31, 2012 (unaudited)		61,024			326	$	313,703		$	301		$	(26,652	)	$	287,352

(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


	Six Months Ended March 31,
(in thousands - unaudited)	2012			2011

Cash flows provided by (used in) operating activities:
Net income	$	43,413		$	69,239

Adjustment to reconcile net income to net cash provided by (used in) operating activities:
(Increase) decrease in fair value of derivative instruments		(9,863	)		(27,167	)
Depreciation and amortization		8,117			10,702
Loss on redemption of debt		—			1,700
Provision for losses on accounts receivable		6,249			7,873
Change in deferred taxes		22,930			37,858
Changes in operating assets and liabilities:
Increase in receivables		(111,154	)		(213,123	)
Decrease in inventories		36,115			27,835
Increase in weather hedge contract receivable		(12,500	)		—
Decrease (increase) in other assets		8,896			(3,431	)
Increase (decrease) in accounts payable		(4,148	)		6,099
Decrease in customer credit balances		(36,302	)		(52,242	)
Increase in other current and long-term liabilities		12,487			31,965

Net cash used in operating activities		(35,760	)		(102,692	)


Cash flows provided by (used in) investing activities:
Capital expenditures		(2,659	)		(2,721	)
Proceeds from sales of fixed assets		272			68
Acquisitions		(26,157	)		(1,791	)

Net cash used in investing activities		(28,544	)		(4,444	)


Cash flows provided by (used in) financing activities:
Revolving credit facility borrowings		86,252			88,416
Revolving credit facility repayments		(53,849	)		(56,823	)
Repayment of debt		—			(82,499	)
Proceeds from the issuance of debt		—			124,188
Debt extinguishment costs		—			(1,409	)
Distributions		(9,954	)		(10,162	)
Unit repurchase		(19,555	)		—
Deferred charges		(326	)		(3,817	)

Net cash provided by financing activities		2,568			57,894


Net decrease in cash and cash equivalents		(61,736	)		(49,242	)

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

Cash and cash equivalents at end of period	$	25,053		$	11,820

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 March 31, 2012, had outstanding 61.0 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 March 31, 2012 served approximately 410,000 full-service residential and commercial home heating oil and propane customers. Petro also sold home heating oil, gasoline and diesel fuel to approximately 41,000 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 March 31, 2012, 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. By February 2012, all 7.25 million common units authorized for repurchase under the Plan II program were repurchased at an average price paid per unit of $4.94 and were retired. The Partnership’s repurchase activities took into account SEC safe harbor rules and guidance for issuer repurchases.

The BOD has not authorized the repurchase of any additional units.


(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

Plan II - January 2012		1,220	$	4.63		277
Plan II - February 2012		277	$	4.54		—


Plan II - Second quarter fiscal year 2012 total		1,497	$	4.62		—


Plan II - Total number of units repurchased		7,250	$	4.94		—

(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 six month period ended March 31, 2012 and March 31, 2011 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, weather hedge contract recoveries, 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 March 31,				Six Months Ended March 31,
(in thousands, except per unit data)	2012		2011		2012		2011
Net income	$	40,482	$	48,681	$	43,413	$	69,239
Less General Partners’ interest in net income		213		236		228		335

Net income available to limited partners		40,269		48,445		43,185		68,904

Less dilutive impact of theoretical distribution of earnings under FASB ASC 260-10-45-60		6,656		7,308		6,339		11,320

Limited Partner’s interest in net income under FASB ASC 260-10-45-60	$	33,613	$	41,137	$	36,846	$	57,584


Per unit data:
Basic and diluted net income available to limited partners	$	0.66	$	0.72	$	0.69	$	1.03

Less dilutive impact of theoretical distribution of earnings under FASB ASC 260-10-45-60		0.11		0.11		0.10		0.17

Limited Partner’s interest in net income under FASB ASC 260-10-45-60	$	0.55	$	0.61	$	0.59	$	0.86


Weighted average number of Limited Partner units outstanding		61,474		67,078		62,839		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)	March 31, 2012		September 30, 2011

Liquid product	$	29,112	$	64,907
Parts and equipment		16,196		15,629

	$	45,308	$	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 March 31, 2012, the Partnership had 0.4 million gallons of physical inventory and had 5.2 million gallons of swap contracts to buy heating oil; 0.8 million gallons of call options; 3.6 million gallons of put options and 42.3 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 March 31, 2012 had 34.5 million gallons of future contracts to buy heating oil; 37.5 million gallons of future contracts to sell heating oil; and 3.9 million gallons of swap contracts to sell heating oil. To hedge a portion of its internal fuel usage, the Partnership as of March 31, 2012, had 0.8 million gallons of swap contracts to buy gasoline; and 0.4 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 March 31, 2011, the Partnership had 0.7 million gallons of physical inventory and had 3.4 million gallons of swap contracts to buy heating oil; 8.3 million gallons of call options; 2.9 million gallons of put options and 36.1 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 March 31, 2011 had 29.4 million gallons of future contracts to buy heating oil; 33.6 million gallons of future contracts to sell heating oil; and 3.2 million gallons of swap contracts to sell heating oil. To hedge a portion of its internal fuel usage, the Partnership as of March 31, 2011, had 0.6 million gallons of swap contracts to buy gasoline; and 0.4 million gallons of swap contracts and 0.5 million gallons of synthetic calls to buy diesel.

The Partnership’s derivative instruments are with the following counterparties: JPMorgan Chase Bank, N.A., Cargill, Inc., Bank of America, N.A., Societe Generale, Bank of Montreal, Newedge USA, LLC, Wells Fargo Bank, N.A., Key Bank, N.A., and Regions Financial Corporation. 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 March 31, 2012, the aggregate cash posted as collateral in the normal course of business at counterparties was $0.3 million. Positions with counterparties who are also parties to our revolving credit facility are collateralized under that facility. As of March 31, 2012, $2.5 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 and were either a Level 1 or Level 2 instrument. The fair market value of our Level 1 and Level 2 derivative assets and liabilities are calculated by our counter-parties and are independently validated by the Partnership. The Partnership’s calculations are, for Level 1 derivative assets and liabilities, based on the published New York Mercantile Exchange (“NYMEX”) market prices for the commodity contracts open at the end of the period. For Level 2 derivative assets and liabilities the calculations performed by the Partnership are based on a combination of the NYMEX published market prices and other inputs, including such factors as present value, volatility and duration.

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 March 31, 2012
Commodity contracts	Fair asset and fair liability value of derivative instruments	$	15,012		$	6,186		$	8,826		$	—

Commodity contract assets at March 31, 2012		$	15,012		$	6,186		$	8,826		$	—


Liability Derivatives at March 31, 2012
Commodity contracts	Fair liability and fair asset value of derivative instruments	$	(10,260	)	$	(6,097	)	$	(4,163	)	$	—

Commodity contract liabilities at March 31, 2012		$	(10,260	)	$	(6,097	)	$	(4,163	)	$	—


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
Derivatives Not Designated as Hedging Instruments Under FASB ASC 815-10	Location of (Gain) or Loss Recognized in Income on Derivative	Three Months Ended March 31, 2012			Three Months Ended March 31, 2011			Six Months Ended March 31, 2012			Six Months Ended March 31, 2011
Commodity contracts	Cost of product (a)	$	15,916		$	(5,870	)	$	15,324		$	4,205
Commodity contracts	Cost of installations and service (a)	$	(156	)	$	(321	)	$	(104	)	$	(414	)
Commodity contracts	Delivery and branch expenses (a)	$	(98	)	$	(380	)	$	(90	)	$	(483	)
Commodity contracts	(Increase) / decrease in the fair value of derivative instruments	$	(16,981	)	$	(13,261	)	$	(9,863	)	$	(27,167	)

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

Weather Hedge Contract

To partially mitigate the adverse effect of warm weather on cash flows, the Partnership has used weather hedge contracts for a number of years. The 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.

For the fiscal 2012 heating season, the Partnership entered into a weather hedge contract with Renaissance Trading Ltd. under which it was 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 covered the period from November 1, 2011 through March 31, 2012 taken as a whole, and had a maximum payout of $12.5 million. Temperatures for the period November 1, 2011 through March 31, 2012 taken as a whole met the Payment Threshold and the heating degree-day shortfall during this period resulted in the Partnership recording a weather hedge contract receivable of $12.5 million for the three months ended March 31, 2012. In April 2012, the amount was collected in full. The $12.5 million contractual recovery was recorded as a reduction of expenses in the line item delivery and branch expenses, in the accompanying statements of operations.

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)	March 31, 2012		September 30, 2011

Property and equipment	$	163,649	$	155,426
Less: accumulated depreciation		111,609		108,295

Property and equipment, net	$	52,040	$	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 effect. For the three months ended March 31, 2012, comprehensive income was $40.9 million, comprised of net income of $40.5 million, an unrealized gain on the pension plan obligation of $0.7 million and the corresponding tax effect of $(0.3) million. For the three months ended March 31, 2011, comprehensive income was $49.1 million, comprised of net income of $48.7 million, an unrealized gain on the pension plan obligation of $0.7 million and the corresponding tax effect of $(0.3) million.

For the six months ended March 31, 2012, comprehensive income was $44.2 million, comprised of net income of $43.4 million, an unrealized gain on the pension plan obligation of $1.4 million and the corresponding tax effect of $(0.6) million. For the six months ended March 31, 2011, comprehensive income was $70.0 million, comprised of net income of $69.2 million, an unrealized gain on the pension plan obligation of $1.4 million and the corresponding tax effect of $(0.6) 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 and six months ended March 31, 2012, and 2011 are as follows:


	Three Months Ended March 31,				Six Months Ended March 31,
(in thousands)	2012		2011		2012		2011

Income before income taxes	$	69,873	$	84,149	$	75,456	$	121,718

Current tax expense	$	7,615	$	12,590	$	9,113	$	14,621
Deferred tax expense		21,776		22,878		22,930		37,858

Total tax expense	$	29,391	$	35,468	$	32,043	$	52,479

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, provides financial statement accounting guidance for uncertainty in income taxes and tax positions taken or expected to be taken in a tax return. At March 31, 2012, we had unrecognized income tax benefits totaling $3.3 million including related accrued interest of $0.6 million. These unrecognized tax benefits are primarily the result of Federal tax uncertainties. If recognized, these tax benefits and related interest 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 March 31, 2013. Our continuing practice is to recognize interest 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 the second quarter of fiscal 2012, the Partnership adopted the Financial Accounting Standards Board ("FASB") provisions of 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”). This standard provides for a consistent definition of fair value, and changes some fair value measurement principles and disclosure requirements under U.S. GAAP. There was no impact on our results of operations or the amount of assets and liabilities reported.

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		6,173

Balance as of March 31, 2012	$	205,469

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:


	March 31, 2012						September 30, 2011
(in thousands)	Gross Carrying Amount		Accum. Amortization		Net		Gross Carrying Amount		Accum. Amortization		Net

Customer lists and other intangibles	$	266,378	$	207,280	$	59,098	$	256,172	$	203,824	$	52,348

Amortization expense for intangible assets was $3.5 million for the six months ended March 31, 2012 compared to $5.5 million for the six months ended March 31, 2011. 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	$	6,675
2013	$	7,137
2014	$	7,061
2015	$	6,925
2016	$	6,755

5) Business Combinations

During the six months ended March 31, 2012, the Partnership acquired four heating oil and propane dealers. The aggregate purchase price was approximately $26.2 million, including working capital of $3.4 million and for one acquired company a contingent consideration of up to $0.3 million, to be paid over the two year period following the acquisition date if the acquisition meets certain performance goals. The operating results of these four 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 March 31, 2012, 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 March 31, 2012				At September 30, 2011
	Carrying Amount		Estimated Fair Value (a)		Carrying Amount		Estimated Fair Value (a)
8.875% Senior Notes (b)	$	124,309	$	124,375	$	124,263	$	127,500

Revolving Credit Facility Borrowings (c )		32,403		32,403		—		—

Total debt	$	156,712	$	156,778	$	124,263	$	127,500

Total long-term portion of debt	$	124,309	$	124,375	$	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 March 31, 2012. 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.

With the exception of the period from April 1, 2012 to December 31, 2012 (during which certain of the financial covenants have been modified, as described below), 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 for the trailing twelve months. 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.

In April 2012, the Partnership amended its bank facility (“Second Amendment”) for the period April 1, 2012 to December 31, 2012, to permit payment of distributions as long as Availability, as defined in the bank facility, is not less than $50.0 million and provided that distributions made during such period do not exceed $0.2325 per Common Unit. During this period, the Partnership is not required to meet the fixed charge coverage ratio test of 1.15 to pay distributions.

In addition, the Second Amendment permanently increased the borrowing base for fixed assets and customer lists from $50.0 million to $60.0 million, permits the incurrence of additional subordinated debt of $25.0 million and increased the amount that the Partnership can invest in an unrestricted subsidiary from $10.0 million to $20.0 million.

The amended and restated revolving credit facility prohibits certain activities including investments, acquisitions, asset sales, inter-company dividends or distributions (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 March 31, 2012, $32.4 million was outstanding under the revolving credit facility and $46.9 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 March 31, 2012, Availability was $152.0 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 March 31, 2012, no offerings under this shelf registration have occurred.

7) Employee Pension Plan


	Three Months Ended March 31,						Six Months Ended March 31,
(in thousands)	2012			2011			2012			2011

Components of net periodic benefit cost:
Service cost	$	—		$	—		$	—		$	—
Interest cost		714			748			1,428			1,496
Expected return on plan assets		(941	)		(879	)		(1,882	)		(1,758	)
Net amortization		688			691			1,376			1,382

Net periodic benefit cost	$	461		$	560		$	922		$	1,120

For the six months ended March 31, 2012, the Partnership contributed $1.4 million and expects to make an additional $2.0 million contribution in fiscal 2012 to fund its pension obligation.

8) Supplemental Disclosure of Cash Flow Information


	Six Months Ended March 31,
(in thousands)	2012		2011

Cash paid during the period for:
Income taxes, net	$	781	$	2,263
Interest	$	7,028	$	5,130
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%	$	46	$	9
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

Amendment to Revolving Credit Facility

In April 2012, due to the impact of the warm winter weather on the Partnership's operating results, the Partnership amended its bank facility to permit payment of distributions from April 1 to December 31, 2012 as long as Availability, as defined in the bank facility, is not less than $50.0 million and provided that distributions made during such period does not exceed $0.2325 per Common Unit. During this period the Partnership is not required to meet the fixed charge coverage test of 1.15 in order to pay distributions. Subsequent to December 31, 2012, the Partnership must have Availability of $61.3 million (on a historical pro forma and forward-looking basis) and must meet the fixed charge coverage test of 1.15 in order to pay distributions.

To provide the Partnership with additional financial flexibility for acquisitions, the amendment increases the borrowing base for fixed assets and customer lists from $50.0 million to $60.0 million, permits the incurrence of additional subordinated debt of $25.0 million and increases the amount that the Partnership can invest in an unrestricted subsidiary from $10.0 million to $20.0 million.

Acquisition

In April 2012, the Partnership purchased the customer lists and assets of a home heating oil dealership for an aggregate cost of approximately $12.2 million, including negative net working capital of $3.8 million.

Quarterly Distribution Declared

On April 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 second quarter of fiscal 2012 payable on May 8, 2012, to holders of record on April 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, $4.7 million will be paid to the common unit holders, $0.06 million to the General Partner (including $0.03 million of incentive distributions) and $0.03 million to management pursuant to the management incentive compensation plan which provides for certain members of management to receive incentive distributions that would otherwise be payable to the General Partner.

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

Over the last 30 years, the variation in temperatures in our geographic areas of operations for the six month period ended March 31, have ranged from 21.3% warmer than normal to 8.5% colder than normal. For example, the period from October 1, 2011 to March 31, 2012 was the warmest over the last 30 years, while the period from October 1, 2010 to March 31, 2011 was the eighth coldest. In addition, the six months ended March 31, 2012 was the warmest winter in the past 112 years in the New York City metropolitan area, which is an important area of operations for us.

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:


	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		2.99		3.32		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

Impact on Liquidity of Wholesale Product Cost Volatility

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 entered into a weather hedge contract with Renaissance Trading Ltd. under which we were 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 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 had a maximum payout of $12.5 million. As of March 31, 2012, we had accrued the maximum payout of $12.5 million as a receivable, which was subsequently collected in April 2012. For fiscal 2013, we are evaluating our options for entering into a weather hedge contract. We believe that the cost for a similar contract for fiscal 2013 will be higher than the cost for fiscal 2012.

In our geographic areas of operations, temperatures for the six months ended March 31, 2012 were 21.3% warmer than normal and 22.6% warmer than the six months ended March 31, 2011. The adverse impact of this warm weather on our operating results was only partially offset by the weather hedge contract and was a contributing factor in the Partnership not being able to meet the required fixed charge coverage ratio of 1.15 for the payment of distributions under our revolving credit facility as the fixed charge coverage ratio was 1.14 for the twelve months ended March 31, 2012. In April 2012, we entered into an amendment to our revolving credit facility that permits us to continue paying distributions to our unitholders for the period from April 1, 2012 through December 31, 2012, provided that our Availability (borrowing base less amounts borrowed and letters of credit issued) is in excess of $50.0 million and provided that distributions made during such period does not exceed $0.2325 per Common Unit. During this period, the Partnership will not be required to meet the fixed charge coverage test to pay distributions but will be required to meet the fixed charge coverage test of 1.15 to repurchase units as long as Availability is $61.3 million. In order to pay distributions subsequent to December 31, 2012, 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 1.15. Given the adverse impact of the warmer winter weather on our fiscal 2012 operating results, it may be more difficult for the Partnership to raise capital on attractive economic terms, which could limit the ability of the Partnership to fully implement its business plan until the resumption of more normal weather conditions and operating results.

We believe that the warmer than normal weather for the six months ended March 31, 2012 will adversely impact home heating oil and propane volume sold for the remainder of fiscal 2012 in part because reduced consumption from warmer weather in one period impacts the amount and timing of deliveries in future periods.

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

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. To the extent derivative instruments designated as cash flow hedges 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	$	16,959	$	33,945
2013		16,619		31,588
2014		15,242		26,817
2015		13,905		23,517
2016		12,404		18,102

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;

•

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;

•

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:

•

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;

•

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.

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)
	Gross Customer				Net Attrition			Gross Customer				Net Attrition			Gross Customer				Net Attrition
	Gains		Losses		Net Attrition			Gains		Losses		Net Attrition			Gains		Losses		Net Attrition
First Quarter		25,700		26,600		(900	)		21,900		24,100		(2,200	)		19,000		21,600		(2,600	)
Second Quarter		11,500		19,700		(8,200	)		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		37,200		46,300		(9,100	)		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)
	Gross Customer						Net Attrition			Gross Customer						Net Attrition			Gross Customer						Net Attrition
	Gains			Losses			Net Attrition			Gains			Losses			Net Attrition			Gains			Losses			Net Attrition
First Quarter		6.2	%		6.4	%		(0.2	%)		5.3	%		5.8	%		(0.5	%)		4.8	%		5.5	%		(0.7	%)
Second Quarter		2.7	%		4.7	%		(2.0	%)		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		8.9	%		11.1	%		(2.2	%)		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 three months ended March 31, 2012, gross customer gains declined by 300 accounts which we believe was due in part to the unusually warm weather; during such periods customers may be less attracted to the full range of services that the Partnership is able to provide and instead may seek out lower cost distributors with more limited services. In addition, attracting new customers on favorable economic terms continues to be problematic due to the high cost of home heating oil. Gross customer losses rose by 2,500 accounts due to higher losses to natural gas, customers moving out of existing homes and other losses, of which the largest component is price.

During the first half of fiscal 2012, gross customer gains increased by 3,500 accounts, while gross customer losses increased by 5,000 accounts. The increase in gross customer losses was due largely to losses to natural gas, customers moving out of existing homes, credit losses, and other losses, of which the largest component is price.

During the six months ended March 31, 2012, we lost 1.1% of our home heating oil accounts to natural gas compared to losses of 0.7% for the six months ended March 31, 2011 and 0.6% for the six months ended March 31, 2010. 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 March 31, 2012

Compared to the Three Months Ended March 31, 2011

Volume

For the three months ended March 31, 2012 retail volume of home heating oil and propane decreased by 48.4 million gallons, or 27.1%, to 130.5 million gallons, compared to 178.9 million gallons for the three months ended March 31, 2011. 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 March 31, 2012 were 23.1% warmer than the three months ended March 31, 2011 and 22.0% warmer than normal, as reported by the National Oceanic and Atmospheric Administration (“NOAA”). In the New York City metropolitan area, which is an important area of operations for us, the three months ended March 31, 2012 was the warmest period in the past 112 years and 3.7% warmer than the next warmest comparable period. For the twelve months ended March 31, 2012, net customer attrition for the base business was 4.2%. 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. 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 March 31, 2011		178.9
Acquisitions		5.5
Impact of warmer temperatures		(39.3	)
Net customer attrition		(8.9	)
Other		(5.7	)

Change		(48.4	)


Volume - Three months ended March 31, 2012		130.5

Volume of other petroleum products decreased by 1.0 million gallons, or 6.9%, to 12.8 million gallons for the three months ended March 31, 2012, compared to 13.8 million gallons for the three months ended March 31, 2011, as the additional volume from acquisitions was more than offset by 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 42.9% of total home heating oil volume sales for the three months ended March 31, 2012, compared to 44.1% for the three months ended March 31, 2011. Accordingly, the percentage of home heating oil volume sold to residential price-protected customers increased to 44.5% for the three months ended March 31, 2012, compared to 43.5% for the three months ended March 31, 2011. For the three months ended March 31, 2012, sales to commercial/industrial customers represented 12.6% of total home heating oil volume sales, compared to 12.4% for the three months ended March 31, 2011.

Product Sales

For the three months ended March 31, 2012, product sales decreased $102.2 million, or 14.9%, to $584.2 million, compared to $686.5 million for the three months ended March 31, 2011, as the decline in total volume due largely to the warm winter weather exceeded the impact of higher product selling prices. Selling prices rose in response to higher per gallon wholesale product costs of $0.5516 per gallon.

Installation and Service Sales

For the three months ended March 31, 2012, installation and service sales were unchanged at $45.4 million compared to the three months ended March 31, 2011, as the additional revenue from acquisitions of $1.1 million was offset by a decline in the base business of $1.1 million. Service revenue in the base business declined by $1.2 million, or 3.9%, largely due to a reduction in the customer base.

Cost of Product

For the three months ended March 31, 2012, cost of product decreased $59.9 million, or 11.5%, to $459.2 million, compared to $519.2 million for the three months ended March 31, 2011, as the 27.1% reduction in home heating oil and propane sold more than offset the impact of higher per gallon wholesale product costs of $0.5516, or 20.5%.

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 March 31, 2012 increased by $0.0154 per gallon, or 1.7%, to $0.9331 per gallon, from $0.9177 per gallon during the three months ended March 31, 2011. Product sales and cost of product include home heating oil, propane, other petroleum products and liquidated damages billings.


	Three Months Ended
	March 31, 2012				March 31, 2011
Home Heating Oil and Propane	Amount (in millions)		Per Gallon		Amount (in millions)		Per Gallon
Volume		130.5				178.9

Sales	$	539.4	$	4.1331	$	643.7	$	3.5979
Cost	$	417.6	$	3.2000	$	479.5	$	2.6803


Gross Profit	$	121.8	$	0.9331	$	164.2	$	0.9177


Other Petroleum Products	Amount (in millions)		Per Gallon		Amount (in millions)		Per Gallon
Volume		12.8				13.8

Sales	$	44.8	$	3.4945	$	42.7	$	3.1003
Cost	$	41.6	$	3.2444	$	39.6	$	2.8747


Gross Profit	$	3.2	$	0.2502	$	3.1	$	0.2256


Total Product	Amount (in millions)				Amount (in millions)
Sales	$	584.2			$	686.5
Cost	$	459.2			$	519.2


Gross Profit	$	125.0			$	167.3

For the three months ended March 31, 2012, total product gross profit decreased by $42.3 million to $125.0 million, compared to $167.3 million for the three months ended March 31, 2011, as the impact of higher home heating oil and propane margins ($2.0 million) and the additional gross profit from other petroleum products ($0.1 million) was more than offset by a reduction in gross profit resulting from lower home heating oil and propane volume ($44.4 million).

Cost of Installations and Service

For the three months ended March 31, 2012, cost of installation and service decreased by $1.7 million, or 3.7%, to $44.4 million, compared to $46.1 million for the three months ended March 31, 2011, as a $1.3 million increase due to fiscal 2012 and fiscal 2011 acquisitions was more than offset by a $3.0 million reduction in service costs and installation costs in our base business. This decline in the base business can be attributed to customer attrition and the impact of warm winter weather.

Installation costs increased by $0.3 million to $12.8 million, or 88.5% of installation sales, during the three months ended March 31, 2012, versus $12.5 million, or 90.0% of installation sales during the three months ended March 31, 2011. Service expenses were $31.6 million for the three months ended March 31, 2012 or 102.1% of service sales, and during the three months ended March 31, 2011 were $33.6 million or 106.5% of service sales. We achieved a combined profit from service and installation of $1.0 million for the three months ended March 31, 2012, compared to a combined loss of $0.7 million for the three months ended March 31, 2011. 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 March 31, 2012, the change in the fair value of derivative instruments resulted in a $17.0 million credit due to the expiration of certain hedged positions (a $13.0 million credit) and an increase in the market value for unexpired hedges (a $4.0 million credit).

During the three months ended March 31, 2011, the change in the fair value of derivative instruments resulted in a $13.3 million credit due to the expiration of certain hedged positions (a $5.5 million charge) and an increase in market value for unexpired hedges (a $18.8 million credit).

Delivery and Branch Expenses

For the three months ended March 31, 2012, delivery and branch expenses decreased $20.2 million, or 24.7%, to $61.7 million, compared to $82.0 million for the three months ended March 31, 2011 as the additional expense from acquisitions of $3.0 million was more than offset by a $12.5 million credit recorded under the Partnership's weather hedge contract and lower delivery and branch expenses of $10.7 million due to the decline in home heating oil and propane volume.

On a cents per gallon basis (excluding the impact of the weather hedge contract), delivery and branch expenses for the three months ended March 31, 2012 increased by $0.1106, or 24.1%, to $0.5687, compared to $0.4581 for the three months ended March 31, 2011 due to the fixed nature of certain operating expenses. Such expenses could not be reduced in the near term to match the weather-related decline in home heating oil and propane volume, thus negatively impacting the efficiency of our operations compared to the prior year. In addition, certain costs such as vehicle fuels, credit card processing fees and bad debt expense rose on a cents per gallon basis due to the increase in the cost of home heating oil and petroleum products.

Depreciation and Amortization

For the three months ended March 31, 2012, depreciation and amortization expenses decreased by $0.9 million, or 18.5% to $3.8 million, compared to $4.7 million for the three months ended March 31, 2011.

Amortization expense relating to fiscal 2001 and fiscal 2004 acquisitions with lives of ten years and seven years respectively, decreased by $1.2 million, as they became fully amortized in fiscal 2011. This decrease was partially offset by an increase of $0.3 million relating to fiscal 2012 and fiscal 2011 acquisitions of customer lists with ten year lives and trademarks with twenty year lives.

General and Administrative Expenses

For the three months ended March 31, 2012, general and administrative expenses decreased $0.7 million to $4.6 million, or 13.7%, from $5.3 million for the three months ended March 31, 2011 primarily due to a decline in profit sharing expense of $0.7 million.

The Partnership accrues approximately 6% of adjusted EBITDA as defined in the profit sharing plan for distribution to its employees, and this amount is payable when the Partnership achieves adjusted EBITDA of at least 70% of the amount budgeted. The dollar amount of the profit sharing pool is subject to increases and decreases in line with increases and decreases in adjusted EBITDA.

Interest Expense

For the three months ended March 31, 2012, interest expense decreased by $0.5 million, or 11.3%, to $3.8 million, compared to $4.3 million during the three months ended March 31, 2011.

During the three months ended March 31, 2012, the Partnership borrowed an average of $57.9 million under its revolving credit facility, or $1.1 million higher than the three months ended March 31, 2011, but this resulted in a negligible increase in interest expense as the interest rate on these borrowings declined from 4.3% to 3.0%. In addition, bank fees were lower by $0.3 million due to lower rates on letters of credit and lower unused commitment fees.

Interest Income

For the three months ended March 31, 2012, interest income was unchanged at $1.2 million compared to the three months ended March 31, 2011.

Amortization of Debt Issuance Costs

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

Income Tax Expense

For the three months ended March 31, 2012, income tax expense decreased by $6.1 million, to $29.4 million, from $35.5 million for the three months ended March 31, 2011, due to a decline in pretax income of $14.3 million. The Partnership’s effective tax rate was 42.1% for both the three months ended March 31, 2012 and the three months ended March 31, 2011.

Net Income (Loss)

For the three months ended March 31, 2012, net income decreased $8.2 million to $40.5 million, from $48.7 million for the three months ended March 31, 2011, as the decrease in pretax income of $14.3 million exceeded the decrease in income tax expense of $6.1 million.

Adjusted EBITDA

For the three months ended March 31, 2012, Adjusted EBITDA decreased by $19.7 million, or 24.8%, to $59.7 million as the impact of warmer temperatures (23.1% warmer than the three months ended March 31,2011) and net customer attrition more than offset an increase in Adjusted EBITDA provided by fiscal 2012 and 2011 acquisitions of $2.1 million, an increase in home heating oil and propane per gallon gross profit margins and $12.5 million recorded under the Partnership's weather hedge contract.

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 March 31,
(in thousands)	2012			2011

Net income	$	40,482		$	48,681
Plus:
Income tax expense		29,391			35,468
Amortization of debt issuance cost		385			732
Interest expense, net		2,621			3,078
Depreciation and amortization		3,829			4,699

EBITDA from continuing operations (a)		76,708			92,658
(Increase) / decrease in the fair value of derivative instruments		(16,981	)		(13,261	)

Adjusted EBITDA (a)		59,727			79,397
Add / (subtract)
Income tax expense		(29,391	)		(35,468	)
Interest expense, net		(2,621	)		(3,078	)
Provision for losses on accounts receivable		4,799			5,225
Increase in accounts receivables		(32,043	)		(97,962	)
Decrease in inventories		54,998			38,159
Decrease in customer credit balances		(30,986	)		(29,108	)
Change in deferred taxes		21,776			22,878
Increase in weather hedge contract receivable		(12,500	)
Change in other operating assets and liabilities		5,246			5,975

Net cash provided by (used in) operating activities	$	39,005		$	(13,982	)



Net cash used in investing activities	$	(1,646	)	$	(1,262	)



Net cash provided by (used in) financing activities	$	(26,226	)	$	13,260

(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.

Six Months Ended March 31, 2012

Compared to the Six Months Ended March 31, 2011

Volume

For the six months ended March 31, 2012 retail volume of home heating oil and propane decreased by 70.0 million gallons, or 24.0%, to 221.6 million gallons, compared to 291.6 million gallons for the six months ended March 31, 2011. 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 six months ended March 31, 2012 were 22.6% warmer than the six months ended March 31, 2011 and 21.3% warmer than normal, as reported by the National Oceanic and Atmospheric Administration (“NOAA”). In the New York City metropolitan area, which is an important area of operations for us, the six months ended March 31, 2012 was the warmest period in the last 112 years and was 2.9% warmer than the next warmest comparable period. For the twelve months ended March 31, 2012, net customer attrition for the base business was 4.2%. 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. 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 - Six months ended March 31, 2011		291.6
Acquisitions		9.4
Impact of warmer temperatures		(62.8	)
Net customer attrition		(14.5	)
Other		(2.1	)

Change		(70.0	)


Volume - Six months ended March 31, 2012		221.6

Volume of other petroleum products increased by 1.8 million gallons, or 7.2%, to 27.1 million gallons for the six months ended March 31, 2012, compared to 25.3 million gallons for the six months ended March 31, 2011, 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 42.9% of total home heating oil volume sales for the six months ended March 31, 2012, compared to 44.1% for the six months ended March 31, 2011. Accordingly, the percentage of home heating oil volume sold to residential price-protected customers increased to 44.2% for the six months ended March 31, 2012, compared to 43.3% for the six months ended March 31, 2011. For the six months ended March 31, 2012, sales to commercial/industrial customers represented 12.9% of total home heating oil volume sales, compared to 12.6% for the six months ended March 31, 2011.

Product Sales

For the six months ended March 31, 2012, product sales decreased $100.5 million, or 9.2%, to $1.0 billion, compared to $ 1.1 billion for the six months ended March 31, 2011, as the decline in total volume of 21.5% exceeded the impact of higher product selling prices. Selling prices increased in response to higher per gallon wholesale product costs of $0.5633 per gallon.

Installation and Service Sales

For the six months ended March 31, 2012, installation and service sales increased $0.3 million, or 0.2%, to $100.2 million, compared to $99.9 million for the six months ended March 31, 2011, as the additional revenue from acquisitions of $2.4 million was reduced by a decline in the base business of $2.1 million due to a reduction in the customer base.

Cost of Product

For the six months ended March 31, 2012, cost of product decreased $44.9 million, or 5.5%, to $775.9 million, compared to $820.8 million for the six months ended March 31, 2011, as the reduction in total volume of 21.5% more than offset the impact of higher per gallon wholesale product costs of $0.5633, or 21.7%.

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 six months ended March 31, 2012 increased by $0.0322 per gallon, or 3.6%, to $0.9402 per gallon, from $0.9080 per gallon during the six months ended March 31, 2011. Product sales and cost of product include home heating oil, propane, other petroleum products and liquidated damages billings.


	Six Months Ended
	March 31, 2012				March 31, 2011
Home Heating Oil and Propane	Amount (in millions)		Per Gallon		Amount (in millions)		Per Gallon
Volume		221.6				291.6

Sales	$	898.6	$	4.0547	$	1,017.5	$	3.4897
Cost	$	690.2	$	3.1145	$	752.8	$	2.5818


Gross Profit	$	208.4	$	0.9402	$	264.7	$	0.9080




Other Petroleum Products	Amount (in millions)		Per Gallon		Amount (in millions)		Per Gallon
Volume		27.1				25.3

Sales	$	92.3	$	3.4033	$	73.9	$	2.9194
Cost	$	85.7	$	3.1591	$	68.0	$	2.6881

Gross Profit	$	6.6	$	0.2442	$	5.9	$	0.2313




Total Product	Amount (in millions)				Amount (in millions)
Sales	$	990.9			$	1,091.4
Cost	$	775.9			$	820.8


Gross Profit	$	215.0			$	270.6

For the six months ended March 31, 2012, total product gross profit decreased by $55.6 million to $215.0 million, compared to $270.6 million for the six months ended March 31, 2011, as the impact of higher home heating oil and propane margins ($7.1 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 ($63.5 million).

Cost of Installations and Service

For the six months ended March 31, 2012, cost of installation and service decreased by $2.0 million, or 2.0%, to $96.7 million, compared to $98.7 million for the six months ended March 31, 2011, as a $2.6 million increase due to fiscal 2012 and fiscal 2011 acquisitions was offset by a $4.6 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 22.6% warmer weather.

Installation costs for the six months ended March 31, 2012 were unchanged at $31.0 million compared to installation costs for the six months ended March 31, 2011. Installation costs as a percentage of installation sales for the six months ended March 31, 2012 and March 31, 2011 were 85.1% and 85.6% respectively. Service expenses declined to $65.7 million for the first half of fiscal 2012 or 103.1% of service sales, versus $67.7 million, or 106.2% of service sales for the six months ended March 31, 2011. We achieved a combined profit from service and installation of $3.5 million for the six months ended March 31, 2012, compared to a combined profit of $1.2 million for the six months ended March 31, 2011. 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 six months ended March 31, 2012, the change in the fair value of derivative instruments resulted in a $9.9 million credit due to the expiration of certain hedged positions (a $5.5 million credit) and an increase in the market value for unexpired hedges (a $4.4 million credit).

During the six months ended March 31, 2011, the change in the fair value of derivative instruments resulted in a $27.2 million credit due to the expiration of certain hedged positions (a $5.0 million credit) and an increase in market value for unexpired hedges (a $22.2 million credit).

Delivery and Branch Expenses

For the six months ended March 31, 2012, delivery and branch expenses decreased $18.4 million, or 12.5%, to $129.5 million, compared to $147.9 million for the six months ended March 31, 2011 as the additional expense from acquisitions of $5.5 million was more than offset by a $12.5 million credit recorded under the Partnership's weather hedge contract and lower delivery and branch expenses of $11.4 million due to the decline in home heating oil and propane volume in the base business.

On a cents per gallon basis (excluding the credit recorded under the Partnership's weather hedge contract), delivery and branch expenses for the six months ended March 31, 2012 increased $0.1334, or 26.3%, to $0.6407, compared to $0.5073 for the six months ended March 31, 2011 due to the fixed nature of certain operating expenses. Such expenses could not be reduced in the near term to match the weather-related decline in home heating oil and propane volume, which negatively impacted the efficiency of our operations compared to the prior year. In addition, certain costs such as vehicle fuels, credit card processing fees, and bad debt expense rose on a per gallon basis due to the increase in cost of home heating oil and petroleum products. Generally, operations were inefficient due to the abnormally warm weather experienced during the six months ended March 31, 2012.

Depreciation and Amortization

For the six months ended March 31, 2012, depreciation and amortization expenses decreased by $1.8 million, or 19.6% to $7.5 million, compared to $9.3 million for the six months ended March 31, 2011.

Amortization expense relating to fiscal 2001 and fiscal 2004 acquisitions with lives of ten years and seven years respectively, decreased by $2.5 million, as they became fully amortized in fiscal 2011. This decrease was partially offset by an increase of $0.7 million relating to fiscal 2012 and fiscal 2011 acquisitions of customer lists with ten year lives and trade names acquired with twenty year lives.

General and Administrative Expenses

For the six months ended March 31, 2012, general and administrative expenses decreased $0.3 million to $9.9 million, or 2.6%, from $10.2 million for the six months ended March 31, 2011 as an increase in expenses related to the Partnerships acquisition program of $0.6 million was reduced by a decline in profit sharing expense of $0.9 million.

Interest Expense

For the six months ended March 31, 2012, interest expense decreased by $1.3 million, or 14.7%, to $7.3 million, compared to $8.5 million during the six months ended March 31, 2011. Average long-term debt decreased by $5.4 million, and the weighted average long-term borrowing rate decreased from 9.3% to 8.875%, 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 six months ended March 31, 2012, the Partnership borrowed an average of $32.0 million under its revolving credit facility, or $3.4 million higher than the six months ended March 31, 2011, which resulted in a negligible increase in interest expense as the interest rate on these borrowings declined from 4.3% to 3.2%. In addition, bank fees were lower by $0.7 million due to lower rates on letters of credit and lower unused commitment fees.

Interest Income

For the six months ended March 31, 2012, interest income increased $0.1 million to $1.9 million, compared to $1.8 million for the six months ended March 31, 2011, due to higher finance charge income from acquisitions and higher past due accounts receivable balances.

Amortization of Debt Issuance Costs

For the six months ended March 31, 2012, amortization of debt issuance costs decreased by $0.7 million to $0.7 million, compared to $1.4 million in the six months ended March 31, 2011. This reduction was 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 six months ended March 31, 2012, income tax expense decreased by $20.4 million, to $32.1 million, from $52.5 million for the six months ended March 31, 2011, due to a decline in pretax income of $46.3 million. The Partnership’s effective tax rate was 42.5% for the six months ended March 31, 2012, slightly less than the rate of 43.1% for the six months ended March 31, 2011.

Net Income (Loss)

For the six months ended March 31, 2012, net income decreased $25.8 million to $43.4 million, from $69.2 million for the six months ended March 31, 2011, as the decrease in pretax income of $46.3 million exceeded the decrease in income tax expense of $20.4 million.

Adjusted EBITDA

For the six months ended March 31, 2012, Adjusted EBITDA decreased by $34.7 million, or 30.5%, to $79.1 million as the impact of warmer temperatures (22.6% warmer than the six months ended March 31, 2011) and net customer attrition more than offset an increase in Adjusted EBITDA provided by fiscal 2012 and 2011 acquisitions, an increase in home heating oil and propane per gallon gross profit margins and $12.5 million recorded under the Partnership's weather hedge contract.

EBITDA and Adjusted EBITDA are calculated as follows:


	Six Months Ended March 31,
(in thousands)	2012			2011

Net income	$	43,413		$	69,239
Plus:
Income tax expense		32,043			52,479
Amortization of debt issuance cost		659			1,426
Interest expense, net		5,345			6,766
Depreciation and amortization		7,458			9,276

EBITDA from continuing operations (a)		88,918			139,186

(Increase) / decrease in the fair value of derivative instruments		(9,863	)		(27,167	)
Loss on redemption of debt		—			1,700

Adjusted EBITDA (a)		79,055			113,719

Add / (subtract)
Income tax expense		(32,043	)		(52,479	)
Interest expense, net		(5,345	)		(6,766	)
Provision for losses on accounts receivable		6,249			7,873
Increase in accounts receivables		(111,154	)		(213,123	)
Decrease in inventories		36,115			27,835
Decrease in customer credit balances		(36,302	)		(52,242	)
Change in deferred taxes		22,930			37,858
Increase in weather hedge contract receivable		(12,500	)		—
Change in other operating assets and liabilities		17,235			34,633

Net cash used in operating activities	$	(35,760	)	$	(102,692	)



Net cash used in investing activities	$	(28,544	)	$	(4,444	)



Net cash provided by financing activities	$	2,568		$	57,894

•

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).

During the six months ended March 31, 2012, cash used in operating activities decreased by $66.9 million to $35.8 million, compared to $102.7 million during the six months ended March 31, 2011, as a reduction in cash generated from operations of $29.4 million, a reduction in accounts payable of $10.2 million, a net reduction in accrued income taxes of $4.6 million due largely to lower pretax income, a reduction in amounts due on net hedging settlements of $4.1 million and the recording of a $12.5 million receivable at March 31, 2012 under the Partnership's weather hedge contract was offset by a decline in cash needs for accounts receivable of $102.0 million, a favorable change in inventory of $8.3 million and greater receipts from our customers on a budget payment plan of $15.9 million. Accounts receivable declined as the impact of lower volume due to the warm weather more than offset the impact of higher selling prices and resulted in a lower cash need. Days sales outstanding as of March 31, 2012 were 31.0 days compared to 35.6 days at March 31, 2011 and 32.3 days at March 31, 2010. The difference in weather between the two periods favorably impacted receivables due from our budget payment plan customers, as sales for the six months ended March 31, 2012 were less than expected while sales for the six months ended March 31, 2011 were greater than anticipated. Home heating oil and propane purchases were less in March 2012 than in March 2011 due to lower volume and the corresponding accounts payable to trade creditors declined.

Investing Activities

Our capital expenditures for the six months ended March 31, 2012 totaled $2.7 million, as we invested in computer hardware and software ($0.4 million), refurbished certain physical plants ($0.6 million), expanded our propane operations ($0.8 million) and made additions to our fleet and other equipment ($0.9 million). We also completed four acquisitions for $26.2 million and allocated $16.4 million of the gross purchase price to intangible assets (including $6.2 million to goodwill), $6.3 million to fixed assets and $3.5 to working capital.

Our capital expenditures for the six months ended March 31, 2011 totaled $2.7 million, as we invested in computer hardware and software ($1.1 million), refurbished certain physical plants ($0.6 million), expanded our propane operations ($0.2 million) and made additions to our fleet and other equipment ($0.8 million). We also completed two acquisitions for $1.8 million and allocated $0.4 million of the gross purchase price to intangible assets $0.6 million to fixed assets, $0.3 million to other long-term assets and $0.5 to working capital.

Financing Activities

During the six months ended March 31, 2012, we borrowed $86.3 million under our credit facility and repaid $53.8 million during the period. We also paid distributions of $10.0 million to our common unit holders, $0.1 million to our General Partner (including $0.07 million of incentive distributions as provided in our Partnership Agreement) and repurchased 3.9 million units for $19.6 million in connection with our unit repurchase plan.

During the six months ended March 31, 2011, 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 six months ended March 31, 2011, we paid distributions of $10.1 million to our common unit holders and $0.1 million to our General Partner (including $0.06 million of incentive distributions as provided for in our Partnership Agreement).

FINANCING AND SOURCES OF LIQUIDITY

Liquidity and Capital Resources

Our primary uses of liquidity are to provide funds for our working capital, capital expenditures, distributions on our units, acquisitions and unit repurchases. Our ability to provide funds for such uses 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 March 31, 2012, 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 and the credit markets are receptive, we may seek to offer and sell debt or equity securities under our $250 million shelf registration statement. Given the adverse impact of the warmer winter weather on our fiscal 2012 operating results, it may be more difficult for the Partnership to offer and sell its securities on attractive economic terms, which could limit the ability of the Partnership to fully implement its business plan until the return of more normal weather conditions and operating results.

Our asset based revolving credit 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 March 31, 2012, borrowings under our revolving credit facility were $32.4 million and $46.9 million in letters of credit were outstanding, of which $46.6 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 for the trailing twelve month period. As of March 31, 2012, Availability, as defined in the amended and restated revolving credit facility agreement, was $152.0 million and we were in compliance with the fixed charge coverage ratio.

The adverse impact of this warm weather on our operating results was only partially offset by the weather hedge contract and was a contributing factor in the Partnership not being able to meet the required fixed charge coverage ratio of 1.15 for the payment of distributions under our revolving credit facility as the fixed charge coverage ratio was 1.14 for the twelve months ended March 31, 2012. In April 2012, we entered into an amendment to our revolving credit facility that permits us to continue paying distributions to our unitholders for the period from April 1, 2012 through December 31, 2012, provided that our Availability (as defined in the revolving credit agreement) is in excess of $50.0 million and provided that distributions made during such period does not exceed $0.2325 per Common Unit. During this period, the Partnership will not be required to meet the fixed charge coverage test to pay distributions but will be required to meet the fixed charge coverage test of 1.15 to repurchase units as long as Availability is $61.3 million. In order to pay distributions subsequent to December 31, 2012, 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 1.15.

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 on its Senior Notes for the remainder of fiscal 2012 are $5.5 million. Maintenance capital expenditures for the remainder of fiscal 2012 are estimated to be approximately $2.0 to $2.5 million, excluding the capital requirements for leased fleet. In addition, we plan to invest an estimated $1.0 to $1.5 million in our propane operations for fleet and tank purchases. We estimate that the Partnership will be required to make minimum cash contributions to fund its frozen defined benefit pension obligations for the remainder of fiscal 2012 of $2.0 million and $12.0 million for fiscal 2013—2016. We anticipate paying distributions during the last two quarters of fiscal 2012 at the current level of $0.0775 per unit, for an aggregate of approximately $9.5 million to common unit holders, $0.1 million to our General Partner (including $0.07 million of incentive distribution as provided in our Partnership Agreement) and $0.07 million to management pursuant to the management incentive compensation plan which provides for certain members of management to receive incentive distributions that would otherwise be payable to the General Partner . We continue to seek attractive acquisition opportunities within the Availability constraints of our bank facility and funding resources. In April 2012, we completed one acquisition for $12.2 million.

In February 2012, the Partnership, completed Plan II of its common unit repurchase program and has not authorized the repurchase of any additional units.

Partnership Distribution Provisions

On April 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 May 8, 2012 to holders of record on April 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, $4.7 million will be paid to the common unit holders, $0.06 million to the General Partner (including $0.3 million of incentive distribution as provided in our Partnership Agreement) and $0.03 million to management pursuant to the management incentive compensation plan which provides for certain members of management to receive incentive distributions that would otherwise be payable to the General Partner.

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

In the second quarter of fiscal 2012, the Partnership adopted 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”). There was no impact on our results of operations or the amount of assets and liabilities reported.

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:

•

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 March 31, 2012, we had outstanding borrowings totaling $156.7 million, of which approximately $32.4 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, future cash flows for the next twelve months would decrease $0.3 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 March 31, 2012, the fair market value of these outstanding derivatives would increase by $10.9 million to a value of $15.6 million; and conversely a hypothetical ten percent decrease in the cost of product would decrease the fair market value of these outstanding derivatives by $7.9 million to a negative value of ($3.1) 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 March 31, 2012. 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 March 31, 2012, 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 March 31, 2012, 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 experienced warmer than normal weather conditions in the fiscal 2012 heating season, which had an adverse effect on our fiscal 2012 results of operations and our financial condition.

Given the adverse impact of the warmer winter weather on our fiscal 2012 operating results, it may be more difficult for the Partnership to raise capital on attractive economic terms, which could limit the ability of the Partnership to fully implement its business plan until the resumption of more normal weather conditions and operating results.

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 six months ended March 31, 2012.

Item 6.

Exhibits

(a)	Exhibits Included Within:


10.21		Second Amended dated as of April 6, 2012 to Amended and Restated Revolving Credit Facility Agreement.

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 March 31, 2012 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	May 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	May 7, 2012
Richard G. Oakley	Kestrel Heat LLC
	(Principal Accounting Officer)

SECOND AMENDMENT TO AMENDED AND RESTATED REVOLVING CREDIT FACILITY AGREEMENT

Exhibit 10.21

SECOND AMENDMENT

SECOND AMENDMENT, dated as of April 6, 2012 (this “Amendment”), to the Amended and Restated Credit Agreement, dated as of June 3, 2011 (as amended by the First Amendment, dated as of November 22, 2011, and as further amended, amended and restated, supplemented or otherwise modified from time to time, the “Credit Agreement”), among Petroleum Heat and Power Co., Inc., a Minnesota corporation (the “Borrower”), the other Loan Parties, the Lenders from time to time party hereto, JPMorgan Chase Bank, N.A., a national banking association, as an LC Issuer and as the Agent (in its capacity as the Agent, the “Administrative Agent”), Bank of America, N.A., as Syndication Agent and as an LC Issuer, RBS Citizens, N.A., as Documentation Agent, and Key Bank National Association, PNC Bank, N.A., Regions Bank, TD Bank, N.A. and Wells Fargo Capital Finance, as Senior Managing Agents.

W I T N E S S E T H

WHEREAS, pursuant to the Credit Agreement, the Lenders have agreed to make, and have made, certain loans and other extensions of credit to the Borrower;

WHEREAS, the Borrower has requested that the Credit Agreement be amended as set forth herein; and

WHEREAS, the Required Lenders are willing to agree to this Amendment on the terms set forth herein.

NOW, THEREFORE, in consideration of the premises and mutual covenants contained herein, the parties hereto agree as follows:

1 Capitalized Terms . Capitalized terms used but not defined herein shall have the meanings assigned to such terms in the Credit Agreement.

2 Amendments. The Credit Agreement shall be amended as of the Amendment Effective Date (as defined below) as set forth below.

(a) Amendment to Section 1.1 (Defined Terms). Section 1.1 of the Credit Agreement is hereby amended as follows:

2.2 (i) by deleting the amount “$50,000,000” in clause (d)(i) of the definition of Borrowing Base” and replacing it with “$60,000,000”.

(ii) by replacing the words “in accordance with” in clause (g) of the definition of “Permitted Acquisition” with the words “to the extent required by”.

(iii) by inserting the following new definition of “Second Amendment Effective Date”:

2.3 “Second Amendment Effective Date” means April 6, 2012.

(iv) by deleting the definition of “Subsidiary” in its entirety and replacing it with the following:

2.4 “Subsidiary” of a Person means, subject to the following sentence, any corporation, partnership, limited liability company, association, joint venture or similar business organization more than 50% of the outstanding Capital Stock having ordinary voting power of which shall at the time be owned or controlled by such Person. Unless otherwise expressly provided, all references herein to a “Subsidiary” shall mean a subsidiary of the Borrower other than an Unrestricted Subsidiary (provided that all references to a “Subsidiary” in Sections 6.1(a), (b) and (c) shall mean each subsidiary of the Borrower).

(v) by inserting the following new definition of “Unrestricted Subsidiary” in appropriate alphabetical order:

2.5 “Unrestricted Subsidiary” means any subsidiary of the Borrower that is designated as such by the board of directors of the Borrower; provided that (i) the board of directors of the Borrower shall only be permitted to so designate a subsidiary acquired or organized after the Second Amendment Effective Date as an Unrestricted Subsidiary, (ii) any such designation shall be made substantially concurrently with the acquisition or organization of such subsidiary and any Investments made in such subsidiary by the

Borrower and its Subsidiaries shall be treated as Investments in an Unrestricted Subsidiary and (iii) immediately after giving effect to any such designation there exists no Default or Event of Default. Subject to the foregoing, the board of directors of the Borrower may designate an Unrestricted Subsidiary to be a Subsidiary; provided that no Unrestricted Subsidiary that has been designated as a Subsidiary may again be designated as an Unrestricted Subsidiary.

(b) Amendment to Section 6.16 (Dividends). Section 6.16 of the Credit Agreement is hereby amended by deleting the second sentence of clause (a) thereof in its entirety and replacing it with the following:

2.6 “Notwithstanding the foregoing, any Loan Party may make any dividends or distributions to its respective parent company (and the Parent may make any dividends or distributions to its equity owners) or redeem, repurchase or otherwise acquire or retire any of its Capital Stock so long as (i) with respect to any such dividends or distributions during any period other than the period from April 1, 2012 through December 31, 2012 and with respect to any redemptions, repurchases or other acquisitions or retirements of its Capital Stock during any period, (x) after giving pro forma effect thereto, Availability (with any Suppressed Availability being included in each calculation of Availability pursuant to this clause (x)) was not less than 17.5% of the Aggregate Commitment for any period of three consecutive days during the six-month period ending on the date on which such dividends, distributions, redemptions, repurchases or other acquisitions or retirements of its Capital Stock were made and is not projected to be less than 17.5% of the Aggregate Commitment during the six-month period immediately after the date on which such dividends, distributions, redemptions, repurchases or other acquisitions or retirements of its Capital Stock are made (with such projected Availability to be determined by reference to the average projected Availability on the last day of each of the relevant six months) and (y) the Fixed Charge Coverage Ratio is not less than 1.15 to 1.00 after giving pro forma effect to such distributions as if such distributions were paid on the first day of the relevant period and (ii) with respect to any such dividends or distributions during the period from April 1, 2012 through December 31^,2012, (x) after giving pro forma effect thereto, Availability (with any Suppressed Availability being included in each calculation of Availability pursuant to this clause (x)) was not less than $50,000,000 for any period of three consecutive days during the six-month period ending on the date on which such dividends or distributions were made and is not projected to be less than $50,000,000 during the six-month period immediately after the date on which such dividends or distributions are made (with such projected Availability to be determined by reference to the average projected Availability on the last day of each of the relevant six months) and (y) the aggregate amount of such dividends and distributions made by the Parent during such period does not exceed $0.2325 per unit of Capital Stock plus an additional $115,000 to the General Partner; provided, however, that, in the case of the foregoing clauses (i) and (ii), (1) no Default or Unmatured Default then exists or would result therefrom and (2) the Borrower Representative has delivered a certificate of an Authorized Officer attesting to the matters set forth in clause (i) or (ii) above, as the case may be, and showing in reasonable detail all calculations with respect thereto.”

(c) Amendment to Section 6.17 (Indebtedness). Section 6.17 of the Credit Agreement is hereby amended by deleting the amount “$10,000,000” in clause (l) thereof and replacing it with “$25,000,000”.

(d) Amendment to Section 6.20 (Investments and Acquisitions). Section 6.20 of the Credit Agreement is hereby amended by deleting the word “and” at the end of clause (h) thereof, replacing the period at the end of clause (i) thereof with “; and” and adding the following new clause (j):

2.7 “(j) Investments in Unrestricted Subsidiaries not to exceed $20,000,000 in the aggregate during the term of this Agreement.”

(e) Amendment to Section 6.32 (Parent). Section 6.32 of the Credit Agreement is hereby amended and restated in its entirety as follows:

2.8 “The Parent shall not engage in any trade or business, or own any assets (other than the Capital Stock of its Subsidiaries) or incur any Indebtedness (other than the Secured Obligations, its existing Indebtedness (including the 2010 Parent Notes permitted under Section 6.17(m) and Guaranties); provided that the Parent may also (x) incur Indebtedness to the extent incurred to refinance the 2010 Parent Notes pursuant to Section 6.17(d), (y) incur Indebtedness that is subordinated to the Obligations on terms satisfactory to the Agent in its Permitted Discretion (“Parent Subordinated Debt”) and (z) incur Indebtedness pursuant to Section 6.17(l) to the extent no principal payments are payable with respect thereto prior to the date which is six months after the Facility Termination Date; provided further that, in the case of clauses (y) and (z) above, (i) the Net Cash Proceeds of such Parent Subordinated Debt or other unsecured Indebtedness, as the case may be, are contributed to Petro as a common equity contribution, or as an intercompany loan in accordance with Section 6.17(e), and (ii) the Parent has provided the Agent with all documents evidencing such Parent Subordinated Debt or such other unsecured Indebtedness, as the case may be, at least 5 Business Days prior to the issuance or incurrence thereof.”

(f) Amendment to Section 10.15 (Collateral Matters). Section 10.15 of the Credit Agreement is hereby amended by deleting the word “or” at the end of clause (a)(v) thereof and adding the following immediately before the period at the end of clause (a)(vi) thereof:

2.9 “, or (vii) of any Unrestricted Subsidiary upon the designation of any subsidiary as an Unrestricted Subsidiary by the Borrower in accordance with the terms of this Agreement”

(g) Amendment to Article XV (Guaranty). Article XV of the Credit Agreement is hereby amended by adding the following new Section 15.13 at the end thereof:

2.10 “15.13(Discharge of Guaranty Upon Certain Events). If a Guarantor is designated as an Unrestricted Subsidiary in accordance with the provisions of this Agreement or the Capital Stock of any Guarantor is sold in accordance with the provisions of this Agreement such that the Guarantor is no longer a direct or indirect Subsidiary of the Borrower, then in each case the Guaranty of such Guarantor and any subsidiary of such Guarantor that is a Guarantor hereunder shall automatically be discharged and released.”

3 Conditions to Effectiveness of Amendment . This Amendment shall become effective on the date on which the following conditions precedent have been satisfied or waived (the “Amendment Effective Date”):

(h) The Administrative Agent shall have received a counterpart of this Amendment, executed and delivered by a duly authorized officer of each of (i) the Loan Parties and (ii) the Required Lenders.

(i) The representations and warranties contained in the Credit Agreement and the other Loan Documents shall be true and correct (except to the extent that such representations and warranties specifically refer to an earlier date, in which case such representations and warranties shall be true and correct as of such earlier date) and no Default or Unmatured Default shall exist.

(j) J.P. Morgan Securities LLC, the Administrative Agent and the Lenders shall have received all fees required to be paid, and all reasonable out-of-pocket expenses for which invoices have been presented (including, without limitation, the reasonable fees and disbursements of legal counsel), on or before the Amendment Effective Date.

4 Representations and Warranties. Each Loan Party hereby represents and warrants that (a) each of the representations and warranties contained in Article V of the Credit Agreement are, after giving effect to this Amendment, true and correct in all material respects as if made on and as of the Amendment Effective Date (unless such representations and warranties are stated to relate to a specific earlier date, in which case such representations and warranties shall be true and correct in all material respects as of such earlier date); provided, that each reference to the Credit Agreement therein shall be deemed to be a reference to the Credit Agreement after giving effect to this Amendment and (b) after giving effect to this Amendment, no Default or Unmatured Default has occurred and is continuing.

5 Effects on Credit Documents . (k) Except as specifically amended herein, all Loan Documents shall continue to be in full force and effect and are hereby in all respects ratified and confirmed.

(l) The execution, delivery and effectiveness of this Amendment shall not operate as a waiver of any right, power or remedy of any Lender or the Administrative Agent under any of the Loan Documents, nor constitute a waiver of any provision of the Loan Documents.

6 Expenses. The Borrower agrees to pay and reimburse J.P. Morgan Securities LLC and the Administrative Agent for all of their reasonable out-of-pocket costs and expenses incurred in connection with the preparation and delivery of this Amendment, and any other documents prepared in connection herewith and the transactions contemplated hereby, including, without limitation, the reasonable fees and disbursements of legal counsel.

7 GOVERNING LAW; WAIVER OF JURY TRIAL . THIS AMENDMENT AND THE RIGHTS AND OBLIGATIONS OF THE PARTIES HEREUNDER SHALL BE CONSTRUED IN ACCORDANCE WITH AND BE GOVERNED BY THE LAW OF THE STATE OF NEW YORK. EACH PARTY HERETO HEREBY AGREES AS SET FORTH FURTHER IN SECTIONS 16.2 AND 16.3 OF THE CREDIT AGREEMENT AS IF SUCH SECTIONS WERE SET FORTH IN FULL HEREIN.

8 Amendments; Execution in Counterparts . (m) This Amendment shall not constitute an amendment of any other provision of the Credit Agreement not referred to herein and shall not be construed as a waiver or consent to any further or future action on the part of the Loan Parties that would require a waiver or consent of the Required Lenders or the Administrative Agent. Except as expressly amended hereby, the provisions of the Credit Agreement are and shall remain in full force and effect.

(n) This Amendment may not be amended nor may any provision hereof be waived except pursuant to a writing signed by the Loan Parties, the Administrative Agent and the Required Lenders. This Amendment may be executed in any number of counterparts and by the different parties hereto on separate counterparts, including by means of facsimile or electronic transmission, each of which when so executed and delivered shall be an original, but all of which shall together constitute one and the same instrument.

[Remainder of page intentionally left blank]

IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed and delivered by their respective proper and duly authorized officers as of the day and year first above written.


BORROWER:

PETROLEUM HEAT AND POWER CO., INC.

By:
Name:
Title:

OTHER LOAN PARTIES:

A.P. WOODSON COMPANY
C. HOFFBERGER COMPANY
CHAMPION ENERGY CORPORATION
CHAMPION OIL COMPANY
COLUMBIA PETROLEUM TRANSPORTATION,
LLC
HOFFMAN FUEL COMPANY OF BRIDGEPORT
HOFFMAN FUEL COMPANY OF DANBURY
HOFFMAN FUEL COMPANY OF STAMFORD
J.J. SKELTON OIL COMPANY
LEWIS OIL COMPANY
MAREX CORPORATION
MEENAN HOLDINGS OF NEW YORK, INC.
MEENAN OIL CO., INC.
MINNWHALE LLC
ORTEP OF PENNSYLVANIA, INC.
PETRO HOLDINGS, INC.
PETRO PLUMBING CORPORATION
PETRO, INC.
REGIONOIL PLUMBING, HEATING AND COOLING CO., INC.
RICHLAND PARTNERS, LLC
RYE FUEL COMPANY
STAR ACQUISITIONS, INC.
STAR GAS FINANCE COMPANY
TG&E SERVICE COMPANY, INC.

By:
Name:
Title:

STAR GAS PARTNERS, L.P.

By: KESTREL HEAT, LLC, its General Partner

By:
Name:
Title:


MEENAN OIL CO., L.P.

By:MEENAN OIL CO., INC., its General Partner

By:
Name:
Title:

CFS LLC

By: Richland Partners, LLC, its Sole Member

By:
Name:
Title:

JPMORGAN CHASE BANK, N.A., as Administrative Agent and as a Lender

By:
Name:
Title:

[ ], as a Lender


By:
Name:
Title:

CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO RULE 13A-14(A)/15D-14(A)

Exhibit 31.1

CERTIFICATIONS

I, Daniel P. Donovan, certify that:

1.	I have reviewed this annual report on Form 10-Q of Star Gas Partners, L.P. (“Registrant”);

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)

all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information and;

(b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 7, 2012

/s/ Daniel P. Donovan

Daniel P. Donovan

President and Chief Executive Officer

Star Gas Partners, L.P.

CERTIFICATION OF CHIEF FINANCIAL OFFICER PURSUANT TO RULE 13A-14(A)/15D-14(A)

Exhibit 31.2

CERTIFICATIONS

I, Richard F. Ambury, certify that:

1.	I have reviewed this annual report on Form 10-Q of Star Gas Partners, L.P. (“Registrant”);

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrants’ other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

(b)

(c)

(d)

5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(c)

(d)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 7, 2012

/S/ RICHARD F. AMBURY

Richard F. Ambury

Chief Financial Officer

Star Gas Partners, L.P.

CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO 18 U.S.C. SECTION 1350

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Star Gas Partners, L.P. (the “Partnership”) on Form 10-Q for the quarterly period ended March 31, 2012 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Daniel P. Donovan, President and Chief Executive Officer of the Partnership, certify to my knowledge pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, following due inquiry, I believe that:

(1)

The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)

The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Partnership.

A signed original of this written statement required by Section 906 has been provided to Star Gas Partners, L.P. and will be retained by Star Gas Partners, L.P. and furnished to the Securities and Exchange Commission or its staff upon request.


	STAR GAS PARTNERS, L.P. By: KESTREL HEAT, LLC (General Partner)

Date: May 7, 2012	By:	/s/ Daniel P. Donovan
		Daniel P. Donovan President and Chief Executive Officer Star Gas Partners, L.P.

CERTIFICATION OF CHIEF FINANCIAL OFFICER PURSUANT TO 18 U.S.C. SECTION 1350

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

(1)

The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)

The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Partnership.


	STAR GAS PARTNERS, L.P. By: KESTREL HEAT, LLC (General Partner)

Date: May 7, 2012	By:	/s/ RICHARD F. AMBURY
		Richard F. Ambury Chief Financial Officer Star Gas Partners, L.P.