Edgar Filing: STAR GAS PARTNERS LP

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Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended December 31, 2013

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

For the transition period from to

Commission File Number: 001-14129

STAR GAS PARTNERS, L.P.

(Exact name of registrants as specified in its charters)


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

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

(203) 328-7310

(Registrant’s telephone number, including area code)

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

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

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

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

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

At January 31, 2014, the registrant had 57,467,744 common units outstanding.

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

INDEX TO FORM 10-Q


	Page
Part I Financial Information
Item 1 - Condensed Consolidated Financial Statements
Condensed Consolidated Balance Sheets as of December 31, 2013 (unaudited) and September 30, 2013		3
Condensed Consolidated Statements of Operations (unaudited) for the three months ended December 31, 2013 and December 31, 2012		4
Condensed Consolidated Statements of Comprehensive Income (unaudited) for the three months ended December 31, 2013 and December 31, 2012		5
Condensed Consolidated Statement of Partners’ Capital (unaudited) for the three months ended December 31, 2013		6
Condensed Consolidated Statements of Cash Flows (unaudited) for the three months ended December 31, 2013 and December 31, 2012		7
Notes to Condensed Consolidated Financial Statements (unaudited)		8-18
Item 2 - Management’s Discussion and Analysis of Financial Condition and Results of Operations		19-33
Item 3 - Quantitative and Qualitative Disclosures About Market Risk		34
Item 4 - Controls and Procedures		34

Part II Other Information:
Item 1 - Legal Proceedings		35
Item 1A - Risk Factors		35
Item 2 - Unregistered Sales of Equity Securities and Use of Proceeds		35
Item 6 - Exhibits		35
Signatures		36

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS


(in thousands)	December 31, 2013			September 30, 2013
	(unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	83,234		$	85,057
Receivables, net of allowance of $8,034 and $7,928, respectively		202,814			96,124
Inventories		84,290			68,150
Fair asset value of derivative instruments		3,258			646
Current deferred tax assets, net		24,222			32,447
Prepaid expenses and other current assets		25,152			23,456

Total current assets		422,970			305,880


Property and equipment, net		51,821			51,323
Goodwill		201,130			201,130
Intangibles, net		64,481			66,790
Deferred charges and other assets, net		7,162			7,381

Total assets	$	747,564		$	632,504


LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Accounts payable	$	39,477		$	18,681
Revolving credit facility borrowings		100,348			—
Fair liability value of derivative instruments		1,037			3,999
Accrued expenses and other current liabilities		87,368			87,142
Unearned service contract revenue		49,626			40,608
Customer credit balances		50,078			70,196

Total current liabilities		327,934			220,626


Long-term debt		124,487			124,460
Long-term deferred tax liabilities, net		14,616			19,292
Other long-term liabilities		7,757			8,845

Partners’ capital
Common unitholders		295,427			282,289
General partner		42			3
Accumulated other comprehensive loss, net of taxes		(22,699	)		(23,011	)

Total partners’ capital		272,770			259,281

Total liabilities and partners’ capital	$	747,564		$	632,504

See accompanying notes to condensed consolidated financial statements.

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS


	Three Months Ended December 31,
(in thousands, except per unit data - unaudited)	2013			2012

Sales:
Product	$	463,387		$	454,470
Installations and service		57,223			62,055

Total sales		520,610			516,525
Cost and expenses:
Cost of product		358,577			356,613
Cost of installations and service		53,443			57,221
(Increase) decrease in the fair value of derivative instruments		(5,458	)		7,965
Delivery and branch expenses		68,400			68,387
Depreciation and amortization expenses		4,359			4,358
General and administrative expenses		5,406			4,491
Finance charge income		(1,004	)		(1,088	)

Operating income		36,887			18,578
Interest expense, net		(3,623	)		(3,417	)
Amortization of debt issuance costs		(421	)		(492	)

Income before income taxes		32,843			14,669
Income tax expense		13,555			4,917

Net income	$	19,288		$	9,752
General Partner’s interest in net income		109			53

Limited Partners’ interest in net income	$	19,179		$	9,699



Basic and diluted income per Limited Partner Unit (1):	$	0.29		$	0.15


Weighted average number of Limited Partner units outstanding:
Basic and Diluted		57,511			60,556

(1)	See Note 13 Earnings Per Limited Partner Unit.

See accompanying notes to condensed consolidated financial statements.

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


	Three Months Ended December 31,
(in thousands - unaudited)	2013			2012

Net income	$	19,288		$	9,752

Other comprehensive income:
Unrealized gain on pension plan obligation (1)		528			664
Tax effect of unrealized gain on pension plan		(216	)		(271	)

Total other comprehensive income		312			393


Total comprehensive income	$	19,600		$	10,145

(1)	These items are included in the computation of net periodic pension cost. See Note 9 - Employee Benefit Plan.

See accompanying notes to condensed consolidated financial statements.

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL


	Number of Units
(in thousands - unaudited)	Common			General Partner		Common			General Partner			Accum. Other Comprehensive Income (Loss)			Total Partners’ Capital
Balance as of September 30, 2013		57,718			326	$	282,289		$	3		$	(23,011	)	$	259,281

Net income		—			—		19,179			109			—			19,288
Unrealized gain on pension plan obligation (1)		—			—		—			—			528			528
Tax effect of unrealized gain on pension plan		—			—		—			—			(216	)		(216	)
Distributions		—			—		(4,741	)		(70	)		—			(4,811	)
Retirement of units (2)		(250	)		—		(1,300	)		—			—			(1,300	)

Balance as of December 31, 2013 (unaudited)		57,468			326	$	295,427		$	42		$	(22,699	)	$	272,770

(1)	These items are included in the computation of net periodic pension cost. See Note 9 - Employee Benefit Plan.

(2)	See Note 3 - Common Unit Repurchase and Retirement.

See accompanying notes to condensed consolidated financial statements.

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


	Three Months Ended December 31,
(in thousands - unaudited)	2013			2012

Cash flows provided by (used in) operating activities:
Net income	$	19,288		$	9,752

Adjustment to reconcile net income to net cash provided by (used in) operating activities:
(Increase) decrease in fair value of derivative instruments		(5,458	)		7,965
Depreciation and amortization		4,779			4,850
Provision for losses on accounts receivable		796			1,763
Change in deferred taxes		3,332			864
Changes in operating assets and liabilities:
Increase in receivables		(107,604	)		(106,395	)
Increase in inventories		(16,140	)		(35,683	)
Increase in other assets		(1,977	)		(3,799	)
Increase in accounts payable		21,253			8,878
Decrease in customer credit balances		(20,119	)		(22,603	)
Increase in other current and long-term liabilities		8,711			13,826

Net cash used in operating activities		(93,139	)		(120,582	)


Cash flows provided by (used in) investing activities:
Capital expenditures		(2,992	)		(848	)
Proceeds from sales of fixed assets		71			16

Net cash used in investing activities		(2,921	)		(832	)


Cash flows provided by (used in) financing activities:
Revolving credit facility borrowings		100,348			36,703
Distributions		(4,811	)		(4,781	)
Unit repurchases		(1,300	)		(4,247	)
Deferred charges		—			(36	)

Net cash provided by financing activities		94,237			27,639


Net increase (decrease) in cash and cash equivalents		(1,823	)		(93,775	)

Cash and cash equivalents at beginning of period		85,057			108,091

Cash and cash equivalents at end of period	$	83,234		$	14,316

See accompanying notes to condensed consolidated financial statements.

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

1) Partnership Organization

Star Gas Partners, L.P. (“Star Gas Partners,” the “Partnership,” “we,” “us,” or “our”) is a home heating oil and propane distributor and services provider with one reportable operating segment that principally provides services to residential and commercial customers to heat their homes and buildings. Star Gas Partners is a master limited partnership, which at December 31, 2013, had outstanding 57.5 million common units (NYSE: “SGU”) representing 99.44% limited partner interest in Star Gas Partners, and 0.3 million general partner units, representing 0.56% 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 (the “Board”) is appointed by its sole member, Kestrel Energy Partners, LLC, a Delaware limited liability company (“Kestrel”).

•

The Partnership’s operations are conducted through Petro Holdings, Inc. and its subsidiaries (“Petro”). Petro is a Minnesota corporation that is an indirect wholly-owned subsidiary of the Partnership. Petro is subject to Federal and state corporation income taxes. Petro is a Northeast and Mid-Atlantic region retail distributor of home heating oil and propane that at December 31, 2013 served approximately 407,000 full-service residential and commercial home heating oil and propane customers. Petro also sold home heating oil, gasoline and diesel fuel to approximately 58,000 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 16,000 customers.

•

Star Gas Finance Company is a 100% owned subsidiary of the Partnership. Star Gas Finance Company serves as the co-issuer, jointly and severally with the Partnership, of its $125 million (excluding discount) 8.875% Senior Notes outstanding at December 31, 2013, 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 11—Long-Term Debt and Bank Facility Borrowings)

2) Summary of Significant Accounting Policies

Basis of Presentation

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

The financial information included herein is unaudited; however, such information reflects all adjustments (consisting solely of normal recurring adjustments), which are, in the opinion of management, necessary for the fair statement of financial condition and results for the interim periods. Due to the seasonal nature of the Partnership’s business, the results of operations and cash flows for the three month period ended December 31, 2013 and December 31, 2012 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 U.S. Generally Accepted Accounting Principles (“GAAP”) 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, 2013.

Reclassification

The accompanying December 31, 2012 consolidated statements of operations have been revised from their previous presentation to reclassify finance charge income of $1,088 and present it separately as an element of operating income. Previously, finance charge income was included in the caption interest income in the consolidated statements of operations. This reclassification was made in order to conform with common industry practice regarding the reporting of finance charge income in operating income, and had no impact on net income, financial position, and cash flows for any period. Interest expense, net consists of:


(in thousands)	Three Months Ended December 31,
	2013			2012
Interest expense	$	(3,633	)	$	(3,427	)
Interest income		10			10

Interest expense, net	$	(3,623	)	$	(3,417	)

Comprehensive Income (Loss)

Comprehensive income (loss) is comprised of net income (loss) and other comprehensive income (loss). Other comprehensive income (loss) consists of the unrealized gain (loss) amortization on the Partnership’s pension plan obligation for its two frozen defined benefit pension plans, and the corresponding tax effect.

Recent Accounting Pronouncements

In the first quarter of fiscal 2014, the Partnership adopted the provisions of the Financial Accounting Standards Board (“FASB”) Accounting Standards Update (“ASU”) No. 2011-11, Disclosures about Offsetting Assets and Liabilities. This amendment as clarified by ASU No. 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, applies only to derivatives, repurchase agreements and reverse purchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with specific criteria contained in FASB Accounting Standards Codification or subject to a master netting arrangement or similar agreement. The adoption of this amendment required added disclosures to enable users of our financial statements to understand the effect of those arrangements on our financial position, and did not impact our results of operations or the amount of assets and liabilities reported.

3) Common Unit Repurchase and Retirement

In July 2012, the Board authorized the repurchase of up to 3.0 million of the Partnership’s common units (“Plan III”). In July 2013, the Board authorized an additional 1.9 million common units to be repurchased under its Plan III common unit repurchase plan. The authorized common unit repurchases may be made from time-to-time in the open market, in privately negotiated transactions or in such other manner deemed appropriate by management. There is no guarantee of the exact number of units that will be purchased under the program and the Partnership may discontinue purchases at any time. The program does not have a time limit. The Board may also approve additional purchases of units from time to time in private transactions. The Partnership’s repurchase activities take into account SEC safe harbor rules and guidance for issuer repurchases. All of the common units purchased in the repurchase program will be retired.

Under the Partnership’s second amended and restated credit agreement (see Note 14. Subsequent Events), we must maintain Availability (as defined in the second amended and restated credit facility agreement) of $45 million, 15.0% of the facility size of $300 million (assuming the non-seasonal aggregate commitment is outstanding) on a historical pro forma and forward-looking basis, and a fixed charge coverage ratio of not less than 1.15 in order to repurchase common units. During the three months ended December 31, 2013, the Partnership was in compliance with the equivalent covenant in the credit agreement then in effect.


(in thousands, except per unit amounts)
Period	Total Number of Units Purchased (a)		Average Price Paid per Unit (b)		Maximum Number of Units that May Yet Be Purchased
Plan III - Number of units authorized						4,894
Private transaction - Number of units authorized (c)						1,150

						6,044


Plan III - Fiscal year 2012 total		22	$	4.26		6,022



Plan III - Fiscal year 2013 total (c)		3,284	$	4.63		2,738


Plan III - October 2013 (d)		250	$	5.20		2,488
Plan III - November 2013		—	$	—		2,488
Plan III - December 2013		—	$	—		2,488

Plan III - First quarter fiscal year 2014 total		250	$	5.20		2,488

(a)	Units were repurchased as part of a publicly announced program, except as noted in a private transaction.

(b)	Amounts include repurchase costs.

(c)	Fiscal year 2013 common unit repurchases include 1.15 million common units acquired in a private transaction.

(d)	October 2013 common unit repurchases were acquired in a private transaction.

4) Derivatives and Hedging—Fair Value Measurements and Accounting for the Offsetting of Certain Contracts

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. The Partnership has elected not to designate its derivative instruments as hedging derivatives, but rather as economic hedges whose change in fair value is recognized in our statement of operations in the line item (Increase) decrease in the fair value of derivative instruments. Depending on the risk being economically hedged, realized gains and losses are recorded in cost of product, cost of installations and service, or delivery and branch expenses.

To hedge a substantial majority of the purchase price associated with heating oil gallons anticipated to be sold to its price-protected customers as of December 31, 2013, the Partnership held 1.6 million gallons of physical inventory and had bought 10.0 million gallons of swap contracts, 4.5 million gallons of call options, 6.9 million gallons of put options and 86.0 million net gallons of synthetic calls, all in future months to match anticipated sales. To hedge the inter-month differentials for its price-protected customers, its physical inventory on hand and inventory in transit, the Partnership, as of December 31, 2013, had bought 57.6 million gallons of future contracts, had sold 76.5 million gallons of future contracts and had sold 16.3 million gallons of future swap contracts. In addition to the previously described hedging instruments, the Partnership as of December 31, 2013, had bought corresponding long and short 38.6 million net gallons of swap contracts and bought 3.9 million gallons of spread contracts (simultaneous long and short positions) to lock-in the differential between high sulfur home heating oil and ultra low sulfur diesel. To hedge a majority of its internal fuel usage for fiscal 2014, the Partnership as of December 31, 2013, had bought 2.4 million gallons of future swap contracts.

To hedge a substantial majority of the purchase price associated with heating oil gallons anticipated to be sold to its price-protected customers as of December 31, 2012, the Partnership held 2.4 million gallons of physical inventory and had bought 10.2 million gallons of swap contracts, 3.8 million gallons of call options, 7.8 million gallons of put options and 84.8 million net gallons of synthetic calls, all in future months to match anticipated sales. To hedge the inter-month differentials for its price-protected customers, its physical inventory on hand and inventory in transit, the Partnership, as of December 31, 2012, had bought 66.3 million gallons of future contracts, had sold 76.8 million gallons of future contracts, had bought 13.0 million gallons of diesel swap contracts (for NYS ultra-low sulfur heating oil customers) and had sold 30.8 million gallons of heating oil swap contracts (including 13.0 million gallons designated for NYS ultra-low sulfur heating oil customers). To hedge a majority of its internal fuel usage for fiscal 2013, the Partnership as of December 31, 2012, had bought 2.1 million gallons of future swap contracts.

The Partnership’s derivative instruments are with the following counterparties: Bank of America, N.A., Bank of Montreal, Cargill, Inc., Citibank, N.A., JPMorgan Chase Bank, N.A., Key Bank, N.A., Regions Financial Corporation, Societe Generale, and Wells Fargo Bank, N.A. The Partnership assesses counterparty credit risk and considers it to be low. We maintain master netting arrangements that allow for the non-conditional offsetting of amounts receivable and payable with counterparties to help manage our risks and record derivative positions on a net basis. The Partnership generally does not receive cash collateral from its counterparties and does not restrict the use of cash collateral maintained at counterparties. At December 31, 2013, the aggregate cash posted as collateral in the normal course of business at counterparties was $1.6 million. Positions with counterparties who are also parties to our revolving credit facility are collateralized under that facility. As of December 31, 2013, $5.1 million of hedge positions were secured under the credit facility.

FASB ASC 820-10 Fair Value Measurements and Disclosures, 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 December 31, 2013
Commodity contracts	Fair asset and fair liability value of derivative instruments	$	17,429		$	4,714		$	12,715		$	—

Commodity contract assets at December 31, 2013		$	17,429		$	4,714		$	12,715		$	—


Liability Derivatives at December 31, 2013
Commodity contracts	Fair liability and fair asset value of derivative instruments	$	(15,208	)	$	(4,897	)	$	(10,311	)	$	—

Commodity contract liabilities at December 31, 2013		$	(15,208	)	$	(4,897	)	$	(10,311	)	$	—


Asset Derivatives at September 30, 2013
Commodity contracts	Fair asset and fair liability value of derivative instruments	$	14,467		$	1,175		$	13,292		$	—

Commodity contract assets at September 30, 2013		$	14,467		$	1,175		$	13,292		$	—


Liability Derivatives at September 30, 2013
Commodity contracts	Fair liability and fair asset value of derivative instruments	$	(17,820	)	$	(519	)	$	(17,301	)	$	—

Commodity contract liabilities at September 30, 2013		$	(17,820	)	$	(519	)	$	(17,301	)	$	—

The Partnership’s derivative assets (liabilities) offset by counterparty and subject to an enforceable master netting arrangement are listed on the following table.


(In thousands)									Gross Amounts Not Offset in the Statement of Financial Position
Offsetting of Financial Assets (Liabilities) and Derivative Assets (Liabilities)	Gross Assets Recognized		Gross Liabilities Offset in the Statement of Financial Position			Net Assets (Liabilities) Presented in the Statement of Financial Position			Financial Instruments		Cash Collateral Received		Net Amount
Fair asset value of derivative instruments	$	14,967	$	(11,709	)	$	3,258		$	—	$	—	$	3,258
Fair liability value of derivative instruments		2,462		(3,499	)		(1,037	)		—		—		(1,037	)

Total at December 31, 2013	$	17,429	$	(15,208	)	$	2,221		$	—	$	—	$	2,221


Fair asset value of derivative instruments	$	7,254	$	(6,608	)	$	646		$	—	$	—	$	646
Fair liability value of derivative instruments		7,213		(11,212	)		(3,999	)		—		—		(3,999	)

Total at September 30, 2013	$	14,467	$	(17,820	)	$	(3,353	)	$	—	$	—	$	(3,353	)


(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 December 31, 2013			Three Months Ended December 31, 2012
Commodity contracts	Cost of product (a)	$	5,311		$	4,876
Commodity contracts	Cost of installations and service (a)	$	(8	)	$	(89	)
Commodity contracts	Delivery and branch expenses (a)	$	(39	)	$	(85	)
Commodity contracts	(Increase) / decrease in the fair value of derivative instruments	$	(5,458	)	$	7,965

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

5) Inventories

The Partnership’s product inventories are stated at the lower of cost or market computed on the weighted average cost method. All other inventories, representing parts and equipment are stated at the lower of cost or market using the FIFO method. The components of inventory were as follows (in thousands):


	December 31, 2013		September 30, 2013
Product	$	66,296	$	50,197
Parts and equipment		17,994		17,953

Total inventory	$	84,290	$	68,150

6) Property and Equipment

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


	December 31, 2013		September 30, 2013

Property and equipment	$	172,412	$	170,462
Less: accumulated depreciation		120,591		119,139

Property and equipment, net	$	51,821	$	51,323

7) Other Intangible Assets

Intangibles, net

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


	December 31, 2013						September 30, 2013
	Gross Carrying Amount		Accum. Amortization		Net		Gross Carrying Amount		Accum. Amortization		Net
Customer lists and other intangibles	$	288,011	$	223,530	$	64,481	$	288,011	$	221,221	$	66,790

Amortization expense for intangible assets was $2.3 million for the three months ended December 31, 2013, compared to $2.3 million for the three months ended December 31, 2012. Total estimated annual amortization expense related to intangible assets subject to amortization, for the fiscal year ending September 30, 2014, and the four succeeding fiscal years ending September 30, is as follows (in thousands):


	Estimated Annual Book Amortization Expense
2014	$	9,188
2015	$	9,053
2016	$	8,882
2017	$	8,362
2018	$	7,523

8) Long-Term Debt and Bank Facility Borrowings

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


	December 31, 2013				September 30, 2013
	Carrying Amount		Fair Value (a)		Carrying Amount		Fair Value (a)
8.875% Senior Notes (b)	$	124,487	$	130,938	$	124,460	$	130,000
Revolving Credit Facility Borrowings (c)		100,348		100,348		—		—

Total debt	$	224,835	$	231,286	$	124,460	$	130,000

Total long-term portion of debt	$	124,487	$	130,938	$	124,460	$	130,000

(a)	The Partnership’s fair value estimates of long-term debt are made at a specific point in time, based on Level 2 inputs. Due to the relatively short maturity of the revolving credit facility, the carrying amount approximates fair value.

(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 $0.5 million at December 31, 2013. 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)

At December 31, 2013, the Partnership had an amended and restated asset based revolving credit facility agreement with a bank syndicate comprised of fifteen banks that expired in 2016. Under this agreement, the Partnership was permitted to borrow up to $250 million ($350 million during the heating season of December through April of each year) for working capital purposes (subject to certain borrowing base limitations and coverage ratios) and was permitted to issue up to $100 million in letters of credit.

In January 2014, the Partnership entered into a second amended and restated asset based revolving credit facility agreement with a bank syndicate comprised of fifteen participants, which replaced the existing revolving credit facility. (See Note 14. Subsequent Events).

The second amended and restated revolving credit facility provides the Partnership with the ability to borrow up to $300 million ($450 million during the heating season of December 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 and extends the maturity date to June 2017, or January 2019 if the Partnership has met the conditions of the facility termination date as defined in the agreement and as discussed further below. The Partnership 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, the Partnership can add additional lenders to the group, with the consent of the Agent, which shall not be unreasonably withheld. Obligations under the second amended and restated 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 on the second amended and restated credit facility is LIBOR plus (i) 1.75% (if Availability, as defined in the 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 0.30% per annum.

Under the second amended and restated credit facility, the Partnership is obligated to meet certain financial covenants, including the requirement to maintain at all times either Availability (borrowing base less amounts borrowed and letters of credit issued) of 12.5% of the 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 $45 million, 15.0% of the facility size of $300 million (assuming the non-seasonal aggregate commitment is outstanding), on a historical 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 (Prior to the January 2014 agreement, the Partnership was required to maintain availability of 17.5% of the facility size, on a historical 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). Likewise, no inter-company dividends or distributions can be made (including those needed to pay interest or principle on our 8.875% Senior Notes), except to the Partnership or a wholly owned subsidiary of the Partnership, if the immediately preceding covenants have not been met. Certain restrictions are also imposed by the agreement, 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.

All outstanding amounts owed under the second amended and restated credit facility become due and payable on the facility termination date of June 1, 2017. If the Partnership has repaid, prepaid or otherwise defeased at least $100 million of our 8.875% Senior Notes and Availability is equal to or greater than the aggregate amount required to repay the remaining outstanding 8.875% Senior Notes (“Payoff Amount”), then the facility termination date is January 14, 2019. However, after June 1, 2017, in the event that Availability is less than the Payoff Amount, the facility termination date shall be three days following such date. Notwithstanding this, all outstanding amounts are subject to acceleration upon the occurrence of events of default which the Partnership considers usual and customary for an agreement of this type, including failure to make payments under the second amended and restated credit facility, non-performance of covenants and obligations or insolvency or bankruptcy (as described in the second amended and restated credit facility).

At December 31, 2013, $100.3 million was outstanding under the revolving credit facility and $46.5 million of letters of credit were issued. At September 30, 2013, no amount was outstanding under the revolving credit facility and $44.7 million of letters of credit were issued.

At December 31, 2013, availability was $148.0 million and the Partnership was in compliance with the fixed charge coverage ratio. At September 30, 2013, availability was $164.3 million and the Partnership was in compliance with the fixed charge coverage ratio.

In July 2011, the Partnership’s shelf registration became effective, providing for the sale of up to $250 million in one or more offerings of common units representing limited partnership interests, partnership securities and debt securities; which may be secured or unsecured senior debt securities or secured or unsecured subordinated debt securities. As of December 31, 2013, no offerings under this shelf registration have occurred.

9) Employee Benefit Plan


	Three Months Ended December 31,
(in thousands)	2013			2012

Components of net periodic benefit cost:
Service cost	$	0		$	0
Interest cost		690			620
Expected return on plan assets		(776	)		(948	)
Net amortization		528			664

Net periodic benefit cost	$	442		$	336

For the three months ended December 31, 2013, the Partnership contributed $0.8 million and expects to make an additional $1.2 million contribution in fiscal 2014 to fund its pension obligation.

10) Income Taxes

Star Gas Partners is a master limited partnership and is not subject to tax at the entity level for Federal and state income tax purposes. However, Star Gas Partners income is derived from its corporate subsidiaries, and these financial statements reflect significant Federal and state income taxes relating to the corporate subsidiaries. For the corporate subsidiaries of Star Gas Partners, 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.

Income and losses of Star Gas Partners are allocated directly to the individual partners. Even though Star Gas Partners will generate non-qualifying Master Limited Partnership income through its corporate subsidiaries, distributions from the corporate subsidiaries to Star Gas Partners are generally included in the determination of qualified Master Limited Partnership income. All or a portion of the distributions received by Star Gas Partners from the corporate subsidiaries could be a dividend or capital gain to the individual partners.

The accompanying financial statements are reported on a fiscal year, however, Star Gas Partners and its Corporate subsidiaries file Federal and state income tax returns on a calendar year.

The current and deferred income tax expenses for the three months ended December 31, 2013, and 2012 are as follows (in thousands):


	Three Months Ended
	December 31,
(in thousands)	2013		2012

Income before income taxes	$	32,843	$	14,669

Current tax expense	$	10,223	$	4,053
Deferred tax expense		3,332		864

Total tax expense	$	13,555	$	4,917

As of the calendar tax year ended December 31, 2013, Star Acquisitions, a wholly-owned subsidiary of the Partnership, had an estimated Federal net operating loss carry forward (“NOLs”) of approximately $8.3 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, Uncertain Tax Position, provides financial statement accounting guidance for uncertainty in income taxes and tax positions taken or expected to be taken in a tax return. At December 31, 2013, we had unrecognized income tax benefits totaling $0.8 million including related accrued interest and penalties of $0.1 million. These unrecognized tax benefits are primarily the result of state tax uncertainties. If recognized, these tax benefits would be recorded as a benefit to the effective tax rate.

We believe that the total liability for unrecognized tax benefits will not materially change during the next 12 months ending December 31, 2014. 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, four 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.

11) Supplemental Disclosure of Cash Flow Information


	Three Months Ended
	December 31,
(in thousands)	2013		2012

Cash paid during the period for:
Income taxes, net	$	6,740	$	2,541
Interest	$	6,208	$	6,143
Non-cash financing activities:
Increase in interest expense - amortization of debt discount on 8.875% Senior Note	$	27	$	25

12) Commitments and Contingencies

The Partnership’s operations are subject to the operating hazards and risks normally incidental to handling, storing and transporting and otherwise providing for use by consumers of hazardous liquids such as home heating oil and propane. As a result, at any given time, the Partnership is generally a defendant in various legal proceedings and litigation arising in the ordinary course of business. The Partnership maintains insurance policies 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. The Partnership does not carry business interruption insurance. 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.

13) Earnings (Loss) Per Limited Partner Unit

Income per limited partner unit is computed in accordance with FASB ASC 260-10-05 Earnings Per Share, Master Limited Partnerships (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:


	Three Months Ended
Basic and Diluted Earnings Per Limited Partner:	December 31,
(in thousands, except per unit data)	2013		2012
Net income	$	19,288	$	9,752
Less General Partners’ interest in net income		109		53

Net income available to limited partners		19,179		9,699

Less dilutive impact of theoretical distribution of earnings under FASB ASC 260-10-45-60		2,665		762

Limited Partner’s interest in net income under FASB ASC 260-10-45-60	$	16,514	$	8,937


Per unit data:
Basic and diluted net income available to limited partners	$	0.33	$	0.16

Less dilutive impact of theoretical distribution of earnings under FASB ASC 260-10-45-60		0.04		0.01

Limited Partner’s interest in net income under FASB ASC 260-10-45-60	$	0.29	$	0.15


Weighted average number of Limited Partner units outstanding		57,511		60,556

14) Subsequent Events

Quarterly Distribution Declared

In January 2014, we declared a quarterly distribution of $0.0825 per unit, or $0.33 per unit on an annualized basis, on all common units with respect to the first quarter of fiscal 2014, payable on February 7, 2014, to holders of record on January 30, 2014. 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, $0.1 million to the General Partner (including $0.05 million of incentive distribution as provided in our Partnership Agreement) and $0.05 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.

Second Amended and Restated Revolving Credit Facility Agreement

In January 2014, the Partnership entered into a second amended and restated $300 million ($450 million during the heating season of December through April of each year) revolving credit facility agreement.

Acquisition

In January 2014, the Partnership entered into a definitive agreement to acquire Griffith Energy Services, Inc. (“Griffith”) of Columbia, Maryland from Central Hudson Enterprises Corporation. Griffith has operations in Virginia, West Virginia, Delaware, District of Columbia, Maryland, and Pennsylvania and serves approximately 50,000 customers.

Under the terms of the agreement, the Partnership will acquire Griffith stock for $69.9 million plus working capital, which will be determined at closing. The Partnership will purchase Griffith utilizing cash on hand and borrowings on its recently restated and amended credit facility. The acquisition is anticipated to close during the second fiscal quarter of 2014, subject to customary closing conditions and regulatory approval.

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, 2013 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 Annual Report on 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. 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 our historical financial condition and results of our operations and should be read in conjunction with the description of our business 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 the 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, 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 daily 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.

Every ten years, the National Oceanic and Atmospheric Administration (“NOAA”) computes and publishes average meteorological quantities, including the average temperature for the last 30 years by geographical location, and the corresponding degree days. The latest and most widely used data covers the years from 1981 to 2010. Our calculations of normal weather are based on these published 30 year averages for heating degree days, weighted by volume for the locations where we have existing operations.

Home Heating Oil Price Volatility

In recent years, the wholesale price of home heating oil has been volatile, resulting in increased consumer price sensitivity to heating costs and increased gross customer losses. 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 the fiscal years ending September 30, 2010, through 2014, on a quarterly basis, is illustrated in the following chart:


	Fiscal 2014⁽¹⁾				Fiscal 2013 ⁽¹⁾				Fiscal 2012				Fiscal 2011				Fiscal 2010
Quarter Ended	Low		High		Low		High		Low		High		Low		High		Low		High
December 31	$	2.84	$	3.12	$	2.90	$	3.26	$	2.72	$	3.17	$	2.19	$	2.54	$	1.78	$	2.12
March 31		—		—		2.86		3.24		2.99		3.32		2.49		3.09		1.89		2.20
June 30		—		—		2.74		3.09		2.53		3.25		2.75		3.32		1.87		2.35
September 30		—		—		2.87		3.21		2.68		3.24		2.77		3.13		1.92		2.24

(1)	Beginning April 1, 2013, the NYMEX contract specifications were changed from high sulfur home heating oil to ultra low sulfur diesel.

Impact on Liquidity of Wholesale Product Cost Volatility

Our liquidity is adversely impacted in times of increasing wholesale product costs, as we must use more 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.

Weather Hedge Contract—Fiscal Years 2013, 2014 and 2015

In July 2012, the Partnership entered into a weather hedge contract for fiscal years 2013, 2014 and 2015, with Swiss Re Financial Products Corporation, under which Star is entitled to receive a payment of $35,000 per heating degree-day shortfall if the total number of heating degree-days in the period covered is less than 92.5% of the ten year average (the “Payment Threshold”). The hedge covers the period from November 1 through March 31, taken as a whole, for each respective fiscal year and has a maximum payout of $12.5 million for each fiscal year. The Partnership did not record any benefit under its weather hedge contract during fiscal 2013 and has not recorded any benefit for the three months ended December 31, 2013.

Per Gallon Gross Profit Margins

We believe 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 price or fixed price for home heating oil over a fixed period of time, generally twelve months (“price-protected” customers). 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, thus reducing expected margins.

Derivatives

FASB ASC 815-10-05 Derivatives and Hedging requires 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 guidance, 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 guidance, 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.

New York State Ultra Low Sulfur Fuel Oil Regulation

On July 1, 2012, new regulations went into effect in New York State (an important area of operations for us) that require the use of ultra low sulfur home heating oil (which is essentially ultra low sulfur diesel fuel with a dye additive). The NYMEX continued to trade only the high sulfur home heating oil hedge contract through March 31, 2013. Effective April 1, 2013, the NYMEX contract specifications were changed from high sulfur home heating oil to ultra low sulfur diesel, similar to the New York mandate for home heating oil. Due to the change in the specifications of the NYMEX contract, since April 1, 2013, the Partnership has been required to hedge its purchases of high sulfur home heating oil for sales in states other than New York, with the new NYMEX ultra low sulfur diesel contracts.

Because of differences in the price and availability of ultra low sulfur home heating oil and high sulfur home heating oil, we believe that the change in the NYMEX hedge contracts has increased the complexity, costs and risks inherent in hedging the Partnership’s physical inventory and in its sales to price-protected customers, which may impact home heating oil per gallon gross profit margins for these customers.

Income Taxes

Net Operating Loss Carry Forwards

The Partnership and its corporate subsidiaries file Federal and state income tax returns on a calendar year. As of December 31, 2013, our Federal Net Operating Loss carry forwards (“NOLs”) are estimated to be $8.3 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 based on currently owned assets. Our subsidiaries file their tax returns based on a calendar year. The amounts below are based on our September 30 fiscal year and are reflective of fixed assets additions and acquisitions up to December 31, 2013.

Estimated Depreciation and Amortization Expense


(in thousands) Fiscal Year	Book		Tax
2014	$	18,629	$	30,391
2015		17,145		25,643
2016		15,017		19,388
2017		12,543		11,998
2018		10,403		8,532
2019		9,350		6,806

Non-Deductible Partnership Expenses

The Partnership incurs certain expenses at the Partnership level that are not deductible for Federal or state income tax purposes by our corporate subsidiaries. As a result, our effective tax rate could differ from the statutory rate that would be applicable if such expenses were deductible.

Storm Sandy

On October 29, 2012, the storm known as “Sandy” made landfall in our service area, resulting in widespread power outages for a number of our customers. In addition, certain third-party terminals where we purchase and store liquid product were closed for a short period of time due to damage sustained from the storm or by the loss of power. During the period subsequent to the storm, our operations and systems functioned without any meaningful disruptions.

Deliveries of home heating oil and propane were less than expected for certain of our customers who were without power for several weeks subsequent to Sandy. However, since our operations were able to provide uninterrupted service to current and new customers, our sales of diesel fuel increased during the weeks after the storm, as did our service and installation sales, along with the related costs to provide these services.

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, 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. 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 or lost at newly acquired businesses are included in these calculations. Customer attrition percentage calculations include customers added through acquisitions in the denominators of the calculations on a weighted average basis. Gross customer losses are the result of a number of factors, including price competition, move-outs, 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


	Three Months Ended December 31, 2013						Fiscal Year Ended 2013							Fiscal Year Ended 2012
	Gross Customer				Net		Gross Customer				Net			Gross Customer				Net
	Gains		Losses		Attrition		Gains		Losses		Attrition			Gains		Losses		Attrition
First Quarter		25,800		22,700		3,100		26,100		24,400		1,700			25,700		26,600		(900	)
Second Quarter								13,900		19,300		(5,400	)		11,500		19,700		(8,200	)
Third Quarter								7,100		13,600		(6,500	)		7,000		13,700		(6,700	)
Fourth Quarter								14,400		18,000		(3,600	)		13,000		18,200		(5,200	)

Total		25,800		22,700		3,100		61,500		75,300		(13,800	)		57,200		78,200		(21,000	)

Net customer gains (attrition) as a percentage of the home heating oil and propane customer base


	Three Months Ended December 31, 2013									Fiscal Year Ended 2013									Fiscal Year Ended 2012
	Gross Customer						Net			Gross Customer						Net			Gross Customer						Net
	Gains			Losses			Attrition			Gains			Losses			Attrition			Gains			Losses			Attrition
First Quarter		6.4	%		5.6	%		0.8	%		6.3	%		5.9	%		0.4	%		6.2	%		6.4	%		(0.2	%)
Second Quarter											3.3	%		4.6	%		(1.3	%)		2.7	%		4.7	%		(2.0	%)
Third Quarter											1.7	%		3.3	%		(1.6	%)		1.5	%		3.1	%		(1.6	%)
Fourth Quarter											3.5	%		4.3	%		(0.8	%)		3.0	%		4.1	%		(1.1	%)

Total		6.4	%		5.6	%		0.8	%		14.8	%		18.1	%		(3.3	%)		13.4	%		18.3	%		(4.9	%)

During the first quarter of fiscal 2014, the Partnership grew its account base by 3,100 accounts or 1,400 accounts greater than the first quarter of fiscal 2013. The change was primarily due to lower gross customer losses of 1,700 slightly reduced by fewer gross customer gains of 300.

During the first quarter of fiscal 2014, we lost 0.7% of our home heating oil accounts to natural gas versus 0.7% for the first quarter of fiscal 2013 and 0.6% for the first quarter of fiscal 2012. Conversions to natural gas are increasing and we believe they may continue to do so as natural gas has become significantly less expensive than home heating oil on an equivalent BTU basis. In addition, the states of New York, Connecticut and Pennsylvania are seeking to encourage homeowners to expand the use of natural gas as a heating fuel through legislation and regulatory efforts.

Consolidated Results of Operations

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

Three Months Ended December 31, 2013

Compared to the Three Months Ended December 31, 2012

Volume

For the three months ended December 31, 2013, retail volume of home heating oil and propane increased by 6.6 million gallons, or 6.8%, to 103.7 million gallons, compared to 97.1 million gallons for the three months ended December 31, 2012. For those locations where the Partnership had existing operations during both periods, which we sometimes refer to as the “base business” (i.e., excluding acquisitions), temperatures (measured on a heating degree day basis) for the three months ended December 31, 2013 were 5.5% colder than the three months ended December 31, 2012 but 1.9% warmer than normal, as reported by the National Oceanic and Atmospheric Administration (“NOAA”). For the twelve months ended December 31, 2013, net customer attrition for the base business was 3.0%. Deliveries of home heating oil and propane were greater in the three months ended December 31, 2013 than the three months ended December 31, 2012 due to the impact of Sandy on deliveries for the three months ended December 31, 2012. Certain of our customers were without power for several weeks subsequent to Sandy, which reduced their consumption during that period. The home heating oil and propane volume impact due to Sandy is included in the chart below under the heading “Other.” Due to various reasons including the significant increase in the price per gallon of home heating oil and propane over the last several years, we believe that our customers are adopting conservation measures to use less of such products. The impact of any such conservation, along with any period-to-period differences in delivery scheduling, the timing of accounts added or lost during the fiscal years, equipment efficiency and other volume variances not otherwise described, are also included in the chart under the heading “Other.” 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 and certain assumptions, is found below:


(in millions of gallons)	Heating Oil and Propane
Volume - Three months ended December 31, 2012		97.1
Acquisitions		0.5
Impact of colder temperatures		5.0
Net customer attrition		(3.6	)
Other		4.7

Change		6.6


Volume - Three months ended December 31, 2013		103.7

The following chart sets forth the percentage by volume of total home heating oil sold to residential variable-price customers, residential price-protected customers and commercial/industrial customers for the three months ended December 31, 2013, compared to the three months ended December 31, 2012:


	Three Months Ended
Customers	December 31, 2013			December 31, 2012
Residential Variable		40.4	%		42.2	%
Residential Price-Protected		45.5	%		43.5	%
Commercial/Industrial		14.1	%		14.3	%

Total		100.0	%		100.0	%

Volume of other petroleum products decreased by 1.8 million gallons, or 10.4%, to 15.0 million gallons for the three months ended December 31, 2013, compared to 16.8 million gallons for the three months ended December 31, 2012. Volume sold for motor fuels were favorably impacted during the three months ended December 31, 2012 due to an increase in demand for motor fuels as a result of Sandy.

Product Sales

For the three months ended December 31, 2013, product sales increased $8.9 million, or 2.0%, to $463.4 million, compared to $454.5 million for the three months ended December 31, 2012, as an increase in total volume of 4.3% was somewhat reduced by lower product selling prices.

Installation and Service Sales

For the three months ended December 31, 2013, installation and service sales decreased $4.9 million, or 7.8%, to $57.2 million, compared to $62.1 million for the three months ended December 31, 2012, as the additional revenue from acquisitions of $0.3 million was more than offset by a decrease in the base business of $5.2 million. During the three months ended December 31, 2012, the impact of Sandy favorably impacted service and installation revenues.

Cost of Product

For the three months ended December 31, 2013, cost of product increased $2.0 million, or 0.6%, to $358.6 million, compared to $356.6 million for the three months ended December 31, 2012, as an increase in total volume of 4.3% and was slightly reduced by the impact of lower per gallon wholesale product costs.

Gross Profit—Product

The table below calculates the Partnership’s per gallon margins and reconciles product gross profit for home heating oil and propane and other petroleum products. We believe the change in home heating oil and propane margins should be evaluated before the effects of increases or decreases in the fair value of derivative instruments, as we believe that realized per gallon margins should not include the impact of non-cash changes in the market value of hedges before the settlement of the underlying transaction. On that basis, home heating oil and propane margins for the three months ended December 31, 2013 increased by $0.0212 per gallon, or 2.2%, to $0.9729 per gallon, from $0.9517 per gallon during the three months ended December 31, 2012. Product sales and cost of product include home heating oil, propane, other petroleum products and liquidated damages billings.


	Three Months Ended
	December 31, 2013				December 31, 2012
Home Heating Oil and Propane	Amount (in millions)		Per Gallon		Amount (in millions)		Per Gallon
Volume		103.7				97.1

Sales	$	413.7	$	3.9878	$	394.6	$	4.0633
Cost	$	312.7	$	3.0149	$	302.2	$	3.1116


Gross Profit	$	100.9	$	0.9729	$	92.4	$	0.9517


Other Petroleum Products	Amount (in millions)		Per Gallon		Amount (in millions)		Per Gallon
Volume		15.0				16.8

Sales	$	49.7	$	3.3103	$	59.9	$	3.5698
Cost	$	45.8	$	3.0517	$	54.4	$	3.2459


Gross Profit	$	3.9	$	0.2586	$	5.4	$	0.3239


Total Product	Amount (in millions)		Amount (in millions)
Sales	$	463.4	$	454.5
Cost	$	358.6	$	356.6


Gross Profit	$	104.8	$	97.9

For the three months ended December 31, 2013, total product gross profit increased by $6.9 million to $104.8 million, compared to $97.9 million for the three months ended December 31, 2012, as the increase in home heating oil and propane volume ($6.3 million), and the impact of higher home heating oil and propane margins ($2.2 million) was somewhat offset by lower other petroleum product gross profit ($1.5 million). During the three months ended December 31, 2012, both volume of other petroleum products and per gallon margins were favorably impacted by an increase in demand as a result of Sandy.

Cost of Installations and Service

For the three months ended December 31, 2013, cost of installation and service decreased by $3.8 million, or 6.6%, to $53.4 million, compared to $57.2 million for the three months ended December 31, 2012, as a $0.3 million increase related to acquisitions was more than offset by a $4.1 million reduction in our base business. During the three months ended December 31, 2012, service and installations costs rose in response to the additional sales from Sandy.

Installation costs for the three months ended December 31, 2013, decreased by $3.5 million, or 15.2%, to $19.2 million, compared to $22.7 million in installation costs for the three months ended December 31, 2012. Installation costs as a percentage of installation sales for the three months ended December 31, 2013 and the three months ended December 31, 2012 were 83.0% and 83.1%, respectively. Service expenses decreased to $34.2 million for the three months ended December 31, 2013, or 100.5%, of service sales, versus $34.5 million, or 99.3% of service sales, for the three months ended December 31, 2012. We achieved a combined profit from service and installation of $3.8 million for the three months ended December 31, 2013, compared to a combined profit of $4.8 million for the three months ended December 31, 2012. This decline of $1.0 million was largely due to the favorable impact of Sandy during the three months ended December 31, 2012 as the demand for new equipment and repairs to existing systems increased as the result of the storm. Management views the service and installation department on a combined basis because many overhead functions and direct expenses such as service technician time cannot be separated or precisely allocated to either service or installation billings.

(Increase) Decrease in the Fair Value of Derivative Instruments

During the three months ended December 31, 2013, the change in the fair value of derivative instruments resulted in a $5.5 million credit due to the expiration of certain hedged positions (a $1.8 million credit) and a increase in market value for unexpired hedges (a $3.7 million credit).

During the three months ended December 31, 2012, the change in the fair value of derivative instruments resulted in a $8.0 million charge due to the expiration of certain hedged positions (a $0.3 million charge) and a decrease in the market value for unexpired hedges (a $7.7 million charge).

Delivery and Branch Expenses

For the three months ended December 31, 2013, delivery and branch expense was $68.4 million, unchanged from the three months ended December 31, 2012. On a cents per gallon basis, delivery and branch expenses for the three months ended December 31, 2013, decreased $0.0248 per gallon, or 3.9%, to $0.5949 per gallon compared to $0.6197 per gallon for the three months ended December 31, 2012, due to certain costs being spread over higher volume.

Depreciation and Amortization

For the three months ended December 31, 2013, depreciation and amortization was unchanged at $4.4 million.

General and Administrative Expenses

For the three months ended December 31, 2013, general and administrative expenses increased $0.9 million, or 20.4 %, to $5.4 million, from $4.5 million for the three months ended December 31, 2012, due primarily to higher legal and professional expenses of $0.5 million and an increase in profit sharing expense of $0.2 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

Finance Charge Income

For the three months ended December 31, 2013, finance charge income decreased $0.1 million to $1.0 million, compared to $1.1 million for the three months ended December 31,2012, due to lower past due accounts receivable balances.

Interest Expense, net

For the three months ended December 31, 2013, net interest expense increased by $0.2 million, or 6.0% to $3.6 million compared to $3.4 million for the three months ended December 31, 2012 largely due to an increase in average borrowings of $23.2 million under the Partnership’s revolving credit facility.

Amortization of Debt Issuance Costs

For the three months ended December 31, 2013, amortization of debt issuance costs decreased by $0.1 million to $0.4 million, compared to $0.5 million in the three months ended December 31, 2012.

Income Tax Expense

For the three months ended December 31, 2013, income tax expense increased by $8.6 million to $13.5 million from $4.9 million for the three months ended December 31, 2012, primarily due to an increase in pretax income of $18.2 million. The Partnership’s effective tax rate was 41.3% for the three months ended December 31, 2013, compared to a rate of 33.5% for the three months ended December 31, 2012. The increase in the 2013 income tax rate compared to the 2012 rate was primarily due to the recording in the three months ended December 31, 2012, of a $1.0 million deferred tax benefit related to an increase in prospective tax deductions.

Net Income

For the three months ended December 31, 2013, net income increased $9.5 million to $19.3 million, from $9.8 million for the three months ended December 31, 2012, as the increase in pretax income of $18.2 million was greater than the increase in income tax expense of $8.6 million.

Adjusted EBITDA

For the three months ended December 31, 2013, Adjusted EBITDA increased by $4.9 million, or 15.8%, to $35.8 million as the impact of an increase in home heating oil and propane volume and higher home heating oil and propane per gallon margins more than offset the decline in net service profitability and lower gross profit from other petroleum products. During the three months ended December 31, 2012, the Partnership’s home heating oil and propane volume was negatively impacted by Sandy, while net service and installation gross profit and gross profit from sales of other petroleum products was positively impacted.

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

EBITDA and Adjusted EBITDA are calculated as follows:


	Three Months Ended December 31,
(in thousands)	2013			2012

Net income	$	19,288		$	9,752
Plus:
Income tax expense		13,555			4,917
Amortization of debt issuance cost		421			492
Interest expense, net		3,623			3,417
Depreciation and amortization		4,359			4,358

EBITDA (i) (a)		41,246			22,936

(Increase) / decrease in the fair value of derivative instruments		(5,458	)		7,965

Adjusted EBITDA (i) (a)		35,788			30,901

Add / (subtract)
Income tax expense		(13,555	)		(4,917	)
Interest expense, net		(3,623	)		(3,417	)
Provision for losses on accounts receivable		796			1,763
Increase in accounts receivables		(107,604	)		(106,395	)
Increase in inventories		(16,140	)		(35,683	)
Decrease in customer credit balances		(20,119	)		(22,603	)
Change in deferred taxes		3,332			864
Change in other operating assets and liabilities		27,986			18,905

Net cash used in operating activities	$	(93,139	)	$	(120,582	)

Net cash used in investing activities	$	(2,921	)	$	(832	)

Net cash provided by financing activities	$	94,237		$	27,639

(i)	Fiscal year 2013 operating income, EBITDA and Adjusted EBITDA have been revised to reflect the reclassification of finance charge income from interest expense, net.

(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;

•

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.

•

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 do not result in actual cash receipts or payment during the period.

Operating Activities

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

For the three months ended December 31, 2013, cash used in operating activities was $93.1 million or $27.4 million less than cash used in operating activities for the three months ended December 31, 2012, of $120.6 million. To take advantage of market conditions at September 30, 2013, the Partnership increased inventory quantities before the first fiscal quarter to a much greater extent than at September 30, 2012. As a result, cash used to finance inventory purchases was $19.5 million less during the three months ended December 31, 2013 than the three months ended December 31, 2012. The timing of payments for purchases of home heating oil inventory largely contributed to an increase in accounts payable and favorably impacted cash flow from operating activities by $12.4 million more for the three months ended December 31, 2013 than the prior year’s comparable quarter. While the Partnership has significantly increased trade credit over the last several years, this increase represents a timing difference and not a permanent increase in cash. The timing of certain payments ($5.1 million), including insurance and amounts due under the Partnership’s profit sharing plan reduced cash provided by operating activities during the three months ended December 31, 2013, compared to the three months ended December 31, 2012.

Investing Activities

Capital expenditures for the three months ended December 31, 2013, totaled $3.0 million, as we invested in computer hardware and software ($0.6 million), refurbished certain physical plants ($0.6 million), expanded our propane operations ($0.9 million) and made additions to our fleet and other equipment ($0.9 million).

Capital expenditures for the three months ended December 31, 2012, totaled $0.8 million, as we invested in computer hardware and software ($0.1 million), refurbished certain physical plants ($0.1 million), expanded our propane operations ($0.5 million) and made additions to our fleet and other equipment ($0.1 million).

Financing Activities

During the three months ended December 31, 2013, we borrowed $100.3 million under our revolving credit facility, paid distributions of $4.7 million to our common unitholders, $0.07 million to our General Partner (including $0.05 million of incentive distributions as provided for in our Partnership Agreement), and repurchased 0.25 million units for $1.3 million.

During the three months ended December 31, 2012, we borrowed $36.7 million under our revolving credit facility, paid distributions of $4.7 million to our common unit holders, $0.06 million to our General Partner (including $0.03 million of incentive distributions as provided for in our Partnership Agreement), and repurchased 1.0 million units for $4.2 million.

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 product costs to customers, the effects of high net customer attrition, conservation and other factors. Capital requirements, at least in the near term, are expected to be provided by cash flows from operating activities, cash on hand as of December 31, 2013, ($83.2 million) 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.

In January 2014, we entered into a second amended and restated asset-based revolving credit facility, which expires in June 2017 or January 2019 if certain conditions have been met, and which provides us with the ability to borrow up to $300 million ($450 million during the heating season from December through April of each year) for working capital purposes (subject to certain borrowing base limitations and coverage ratios), including the issuance of up to $100 million in letters of credit. We can increase the facility size by $100 million without the consent of the bank group. However, the bank group is not obligated to fund the $100 million increase. If the bank group elects not to fund the increase, we can add additional lenders to the group with the consent of the Agent which shall not be unreasonably withheld. Obligations under the revolving credit facility are guaranteed by us and our subsidiaries and secured by liens on substantially all of our assets, including accounts receivable, inventory, general intangibles, real property, fixtures and equipment. As of December 31, 2013, there were $100.3 million borrowings under our revolving credit facility and $46.5 million in letters of credit were outstanding, primarily for current and future insurance reserves.

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 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 December 31, 2013, Availability, as defined in the revolving credit facility agreement, was $148.0 million and the fixed charge coverage ratio for the twelve months ended December 31, 2013, was in excess of 1.1.

Maintenance capital expenditures for the remainder of fiscal 2014 are estimated to be approximately $4.0 to $5.0 million, excluding the capital requirements for leased fleet. In addition, we plan to invest an estimated $1.0 million in our propane operations. Distributions during the remainder of fiscal 2014 at the current quarterly level of $0.0825 per unit (subject to the Board’s quarterly determination of the amount of Available Cash), will aggregate approximately $14.2 million to common unit holders, $0.210 million to our General Partner (including $0.144 million of incentive distribution as provided in our Partnership Agreement) and $0.144 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. For the balance of fiscal 2014, the Partnership’s scheduled interest payments on its Senior Notes, which are due in November 2017, amount to $5.5 million. Based upon certain actuarial assumptions, we estimate that the Partnership will make cash contributions to its frozen defined benefit pension obligations totaling approximately $1.2 million for the remainder of fiscal 2014.

In January 2014, the Partnership entered into a definitive agreement to acquire Griffith Energy Services, Inc. (“Griffith”) of Columbia, Maryland. Griffith has operations in Virginia, West Virginia, Delaware, District of Columbia, Maryland, and Pennsylvania and serves approximately 50,000 customers. Under the terms of the agreement, the Partnership will acquire the equity of Griffith for $69.9 million plus working capital, which will be determined at closing. The Partnership will purchase Griffith utilizing cash on hand and its recently restated and amended credit facility. The acquisition is anticipated to close during the second fiscal quarter of 2014, subject to customary closing conditions and regulatory approval.

Contractual Obligations and Off-Balance Sheet Arrangements

There has been no material change to Contractual Obligations and Off-Balance Sheet Arrangements since our September 30, 2013, Form 10-K disclosure and therefore, the table has not been included in this Form 10-Q.

Recent Accounting Pronouncements

The following new accounting standard was adopted by the Partnership in the quarter ended December 31, 2013, and had no impact on our results of operations or the amount of assets and liabilities reported:

•

ASU No. 2011-11, Disclosures about Offsetting Assets and Liabilities.

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

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

At December 31, 2013, we had outstanding borrowings totaling $224.8 million, of which approximately $100.3 million is subject to variable interest rates under our revolving credit facility. In the event that interest rates associated with this facility were to increase 100 basis points, the after tax impact on future cash flows would be a decrease of $0.6 million.

We also use derivative financial instruments to manage our exposure to market risk related to changes in the current and future market price of home heating oil. The value of market sensitive derivative instruments is subject to change as a result of movements in market prices. Sensitivity analysis is a technique used to evaluate the impact of hypothetical market value changes. Based on a hypothetical ten percent increase in the cost of product at December 31, 2013, the fair market value of these outstanding derivatives would increase by $13.2 million to a value of $15.4 million; and conversely a hypothetical ten percent decrease in the cost of product would decrease the fair market value of these outstanding derivatives by $12.9 million to a negative value of $(10.7) million.

Item 4.

Controls and Procedures

a) Evaluation of disclosure controls and procedures.

The General Partner’s principal executive officer and its principal financial officer evaluated the effectiveness of the Partnership’s disclosure controls and procedures (as that term is defined in Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended) as of December 31, 2013. Based on that evaluation, such principal executive officer and principal financial officer concluded that the Partnership’s disclosure controls and procedures were effective as of December 31, 2013 at the reasonable level of assurance. For purposes of Rule 13a-15(e), the term disclosure controls and procedures means controls and other procedures of an issuer that are designed to ensure that information required to be disclosed by the issuer in the reports that it files or submits under the Act (15 U.S.C. 78a et seq.) is recorded, processed, summarized and reported, within the time periods specified in the Commission’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Act is accumulated and communicated to the issuer’s management, including its principal executive and principal financial officer, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

b) Change in Internal Control over Financial Reporting.

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

c) The General Partner and the Partnership believe that a controls system, no matter how well designed and operated, cannot provide absolute assurance that the objectives of the controls system are met, and no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within a Partnership have been detected. Therefore, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Our disclosure controls and procedures are designed to provide such reasonable assurances of achieving our desired control objectives, and the principal executive officer and principal financial officer of our general partner have concluded, as of December 31, 2013, 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 2013 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.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

See Note 3. to the Consolidated Financial Statements for information concerning the Partnership’s repurchase of common units in the three months ended December 31, 2013.

Item 6.

Exhibits

(a)	Exhibits Included Within:


10.24		Second Amended and Restated Revolving Credit Facility Agreement dated January 14, 2014.

10.25		Second Amended and Restated Pledge and Security Agreement dated January 14, 2014.

10.26		Stock Purchase Agreement between Central Hudson Enterprises Corporation and Petro Holdings, Inc. dated as of January 27, 2014.

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

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

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

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

101		The following materials from the Star Gas Partners, L.P. Quarterly Report on Form 10-Q for the quarter ended December 31, 2013 formatted in Extensible Business Reporting Language (XBRL): (i) the Condensed Consolidated Balance Sheets, (ii) the Condensed Consolidated Statements of Operations, (iii) the Condensed Consolidated Statements of Comprehensive Income, (iv) the Condensed Consolidated Statements of Partners’ Capital, (v) the Condensed Consolidated Statements of Cash Flows and (vi) 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.

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 Richard F. Ambury	Executive Vice President, Chief Financial Officer, Treasurer and Secretary Kestrel Heat LLC (Principal Financial Officer)	February 5, 2014
/s/ RICHARD F. AMBURY Richard F. Ambury		February 5, 2014

Signature	Title	Date

/s/ RICHARD G. OAKLEY Richard G. Oakley	Vice President - Controller Kestrel Heat LLC (Principal Accounting Officer)	February 5, 2014

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company