Edgar Filing: STAR GAS PARTNERS LP

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2014

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

For the transition period from to

Commission File Number: 001-14129

STAR GAS PARTNERS, L.P.

(Exact name of registrants as specified in its charters)


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

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

(203) 328-7310

(Registrant’s telephone number, including area code)

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

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

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

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

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

At April 30, 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 March 31, 2014 (unaudited) and September 30, 2013		3
Condensed Consolidated Statements of Operations (unaudited) for the three and six months ended March 31, 2014 and March 31, 2013		4
Condensed Consolidated Statements of Comprehensive Income (unaudited) for the three and six months ended March 31, 2014 and March 31, 2013		5
Condensed Consolidated Statement of Partners’ Capital (unaudited) for the six months ended March 31, 2014		6
Condensed Consolidated Statements of Cash Flows (unaudited) for the six months ended March 31, 2014 and March 31, 2013		7
Notes to Condensed Consolidated Financial Statements (unaudited)		8-19
Item 2 - Management’s Discussion and Analysis of Financial Condition and Results of Operations		20-42
Item 3 - Quantitative and Qualitative Disclosures About Market Risk		42
Item 4 - Controls and Procedures		43

Part II Other Information:
Item 1 - Legal Proceedings		44
Item 1A - Risk Factors		44
Item 2 - Unregistered Sales of Equity Securities and Use of Proceeds		44
Item 6 - Exhibits		44
Signatures		45

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS


(in thousands)	March 31, 2014			September 30, 2013
	(unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	12,955		$	85,057
Receivables, net of allowance of $10,960 and $7,928, respectively		377,817			96,124
Inventories		60,147			68,150
Fair asset value of derivative instruments		47			646
Current deferred tax assets, net		12,229			32,447
Prepaid expenses and other current assets		25,745			23,456

Total current assets		488,940			305,880


Property and equipment, net		68,996			51,323
Goodwill		204,268			201,130
Intangibles, net		110,899			66,790
Deferred charges and other assets, net		11,175			7,381

Total assets	$	884,278		$	632,504


LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Accounts payable	$	42,085		$	18,681
Revolving credit facility borrowings		165,741			—
Fair liability value of derivative instruments		2,917			3,999
Accrued expenses and other current liabilities		141,552			87,142
Unearned service contract revenue		49,610			40,608
Customer credit balances		22,289			70,196

Total current liabilities		424,194			220,626


Long-term debt		124,515			124,460
Long-term deferred tax liabilities, net		7,697			19,292
Other long-term liabilities		7,385			8,845

Partners’ capital
Common unitholders		342,608			282,289
General partner		266			3
Accumulated other comprehensive loss, net of taxes		(22,387	)		(23,011	)

Total partners’ capital		320,487			259,281

Total liabilities and partners’ capital	$	884,278		$	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 March 31,						Six Months Ended March 31,
(in thousands, except per unit data - unaudited)	2014			2013			2014			2013

Sales:
Product	$	839,953		$	732,949		$	1,303,340		$	1,187,419
Installations and service		52,288			52,190			109,511			114,245

Total sales		892,241			785,139			1,412,851			1,301,664
Cost and expenses:
Cost of product		639,564			571,790			998,141			928,403
Cost of installations and service		53,032			51,338			106,475			108,559
(Increase) decrease in the fair value of derivative instruments		4,105			(3,447	)		(1,353	)		4,518
Delivery and branch expenses		92,428			83,322			160,828			151,709
Depreciation and amortization expenses		4,917			4,321			9,276			8,679
General and administrative expenses		6,449			4,761			11,855			9,252
Finance charge income		(2,207	)		(2,174	)		(3,211	)		(3,262	)

Operating income		93,953			75,228			130,840			93,806
Interest expense, net		(4,274	)		(4,014	)		(7,897	)		(7,431	)
Amortization of debt issuance costs		(390	)		(418	)		(811	)		(910	)

Income before income taxes		89,289			70,796			122,132			85,465
Income tax expense		37,073			29,117			50,628			34,034

Net income	$	52,216		$	41,679		$	71,504		$	51,431
General Partner’s interest in net income		294			225			403			278

Limited Partners’ interest in net income	$	51,922		$	41,454		$	71,101		$	51,153



Basic and diluted income per Limited Partner Unit (1):	$	0.75		$	0.58		$	1.03		$	0.72


Weighted average number of Limited Partner units outstanding:
Basic and Diluted		57,468			59,837			57,490			60,192

(1)	See Note 14 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 March 31,						Six Months Ended March 31,
(in thousands - unaudited)	2014			2013			2014			2013

Net income	$	52,216		$	41,679		$	71,504		$	51,431

Other comprehensive income:
Unrealized gain on pension plan obligation (1)		528			664			1,056			1,328
Tax effect of unrealized gain on pension plan		(216	)		(271	)		(432	)		(542	)

Total other comprehensive income		312			393			624			786


Total comprehensive income	$	52,528		$	42,072		$	72,128		$	52,217

(1)	These items are included in the computation of net periodic pension cost. See Note 10 - 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		—			—		71,101			403			—			71,504
Unrealized gain on pension plan obligation (1)		—			—		—			—			1,056			1,056
Tax effect of unrealized gain on pension plan		—			—		—			—			(432	)		(432	)
Distributions		—			—		(9,482	)		(140	)		—			(9,622	)
Retirement of units (2)		(250	)		—		(1,300	)		—			—			(1,300	)

Balance as of March 31, 2014 (unaudited)		57,468			326	$	342,608		$	266		$	(22,387	)	$	320,487

(1)	These items are included in the computation of net periodic pension cost. See Note 10 - 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


	Six Months Ended March 31,
(in thousands - unaudited)	2014			2013

Cash flows provided by (used in) operating activities:
Net income	$	71,504		$	51,431

Adjustment to reconcile net income to net cash provided by (used in) operating activities:
(Increase) decrease in fair value of derivative instruments		(1,353	)		4,518
Depreciation and amortization		10,087			9,589
Provision for losses on accounts receivable		4,478			6,203
Change in deferred taxes		8,190			8,651
Changes in operating assets and liabilities:
Increase in receivables		(240,013	)		(208,565	)
Decrease in inventories		13,146			5,749
Decrease in other assets		3,946			4,071
Increase in accounts payable		12,847			3,884
Decrease in customer credit balances		(52,425	)		(62,389	)
Increase in other current and long-term liabilities		47,893			35,489

Net cash used in operating activities		(121,700	)		(141,369	)


Cash flows provided by (used in) investing activities:
Capital expenditures		(4,982	)		(2,138	)
Proceeds from sales of fixed assets		82			45
Acquisitions (net of cash acquired of $4,151 and $0, respectively)		(97,950	)		—

Net cash used in investing activities		(102,850	)		(2,093	)


Cash flows provided by (used in) financing activities:
Revolving credit facility borrowings		195,482			111,542
Revolving credit facility repayments		(29,741	)		(50,494	)
Distributions		(9,622	)		(9,478	)
Unit repurchases		(1,300	)		(5,595	)
Deferred charges		(2,371	)		(36	)

Net cash provided by financing activities		152,448			45,939


Net decrease in cash and cash equivalents		(72,102	)		(97,523	)

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

Cash and cash equivalents at end of period	$	12,955		$	10,568

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 full service provider specializing in the sale of home heating products and services to residential and commercial customers to heat their homes and buildings. The Partnership also services and sells heating and air conditioning equipment to its home heating oil and propane customers and to a lesser extent, provides these offerings to customers outside of our home heating oil and propane customer base. In certain of our marketing areas, we provide home security and plumbing services primarily to our home heating oil and propane customer base. We also sell diesel fuel, gasoline and home heating oil on a delivery only basis. All of these product and services are offered through our home heating oil and propane locations. The Partnership has one reportable segment for accounting purposes. We are the nation’s largest retail distributor of home heating oil, based upon sales volume, operating throughout the Northeast and Mid-Atlantic.

The Partnership is organized as follows:

•

The Partnership is a master limited partnership, which at March 31, 2014, 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 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 owns 100% of Star Acquisitions, Inc. (“SA”), a Minnesota corporation that owns 100% of Petro Holdings, Inc. (“Petro”). SA and its subsidiaries are subject to Federal and state corporation income taxes. The Partnership’s operations are conducted through Petro and its subsidiaries. Petro is a Northeast and Mid-Atlantic region retail distributor of home heating oil and propane that at March 31, 2014 served approximately 450,000 full-service residential and commercial home heating oil and propane customers. Petro also sold diesel fuel, gasoline and home heating oil to approximately 68,000 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 22,000 customers.

•

Star Gas Finance Company (“SGFC”) is a 100% owned subsidiary of the Partnership. SGFC serves as the co-issuer, jointly and severally with the Partnership, of its $125 million 8.875% Senior Notes outstanding at March 31, 2014, due 2017. SGFC and the Partnership are dependent on distributions, including inter-company interest payments from its subsidiaries, to service the debt issued by SGFC and the Partnership. The distributions from these subsidiaries are not guaranteed and are subject to certain loan restrictions. SGFC has nominal assets and conducts no business operations. (See Note 9—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 six month period ended March 31, 2014 and March 31, 2013 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 March 31, 2013 consolidated statements of operations have been revised from their previous presentation to reclassify finance charge income for the three and six months period of $2.2 million and $3.3 million respectively, 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 March 31,						Six Months Ended March 31,
	2014			2013			2014			2013
Interest expense	$	(4,289	)	$	(4,024	)	$	(7,922	)	$	(7,451	)
Interest income		15			10			25			20

Interest expense, net	$	(4,274	)	$	(4,014	)	$	(7,897	)	$	(7,431	)

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.

3) Common Unit Repurchase and Retirement

In July 2012, the Star Board of Directors (“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 the repurchase of an additional 1.9 million Common Units under Plan III. 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 dated January 14, 2014, in order to repurchase Common Units 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 measured as of the date of repurchase. The Partnership was in compliance with this covenant (or the equivalent covenant under the credit agreement then in effect) for all unit repurchases made during the six months ended March 31, 2014.

The following table shows repurchases under Plan III.


(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 - First quarter fiscal year 2014 total (d)		250	$	5.20		2,488



Plan III - Second quarter fiscal year 2014 total		—	$	—		2,488



Plan III - Six months fiscal year 2014 total		250	$	5.20

(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)	First quarter fiscal year 2014 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, priced purchase commitments and internal fuel usage. 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 its 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 March 31, 2014, the Partnership held 0.3 million gallons of physical inventory and had bought 6.3 million gallons of swap contracts, 1.1 million gallons of call options, 4.2 million gallons of put options and 47.7 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 March 31, 2014, had bought 46.2 million gallons of future contracts, and had sold 60.0 million gallons of future contracts. In addition to the previously described hedging instruments, the Partnership as of March 31, 2014, had bought corresponding long and short 33.1 million net gallons of swap contracts 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 the remainder of fiscal 2014, the Partnership as of March 31, 2014, had bought 1.0 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 March 31, 2013, the Partnership held 0.7 million gallons of physical inventory and had bought 5.0 million gallons of swap contracts, 0.9 million gallons of call options, 3.7 million gallons of put options and 45.4 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 March 31, 2013, had bought 48.5 million gallons of future contracts, had sold 54.3 million gallons of future contracts and had sold 3.0 million gallons of swap contracts. To hedge a majority of its internal fuel usage for the remainder of fiscal 2013, the Partnership as of March 31, 2013, had bought 0.8 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 it maintains at counterparties. At March 31, 2014, 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 March 31, 2014, $7.1 million of hedge positions and payable amounts 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 March 31, 2014
Commodity contracts	Fair asset and fair liability value of derivative instruments	$	6,345					$	6,345		$	—

Commodity contract assets at March 31, 2014		$	6,345		$	—		$	6,345		$	—


Liability Derivatives at March 31, 2014
Commodity contracts	Fair liability and fair asset value of derivative instruments	$	(9,215	)	$	(225	)	$	(8,990	)	$	—

Commodity contract liabilities at March 31, 2014		$	(9,215	)	$	(225	)	$	(8,990	)	$	—


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	$	1,009	$	(962	)	$	47		$	—	$	—	$	47
Fair liability value of derivative instruments		5,336		(8,253	)		(2,917	)		—		—		(2,917	)

Total at March 31, 2014	$	6,345	$	(9,215	)	$	(2,870	)	$	—	$	—	$	(2,870	)


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 March 31, 2014			Three Months Ended March 31, 2013			Six Months Ended March 31, 2014			Six Months Ended March 31, 2013
Closed Positions
Commodity contracts	Cost of product (a)	$	3,216		$	8,544		$	8,527		$	13,420
Commodity contracts	Cost of installations and service (a)	$	(87	)	$	(245	)	$	(95	)	$	(334	)
Commodity contracts	Delivery and branch expenses (a)	$	(75	)	$	(118	)	$	(114	)	$	(203	)

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

Open Positions
Commodity contracts	(Increase) / decrease in the fair value of derivative instruments	$	4,105		$	(3,447	)	$	(1,353	)	$	4,518

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):


	March 31, 2014		September 30, 2013
Product	$	40,332	$	50,197
Parts and equipment		19,815		17,953

Total inventory	$	60,147	$	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):


	March 31, 2014		September 30, 2013

Property and equipment	$	191,174	$	170,462
Less: accumulated depreciation		122,178		119,139

Property and equipment, net	$	68,996	$	51,323

7) Business Combination

On March 4, 2014 (the “Acquisition Date”), the Partnership completed the acquisition of Griffith Energy Services, Inc. (“Griffith”) of Columbia, Maryland from Central Hudson Enterprises Corporation. The Partnership purchased 100% of the stock of Griffith for $98.7 million, consisting of $69.9 million paid for the long term assets and $28.8 million paid for estimated working capital (net of $4.2 million of cash acquired). The estimated working capital is subject to a final post closing adjustment. In addition, the Partnership issued $8.5 million in letters of credit for supply and insurance purposes. There was no long-term debt assumed in the acquisition. The business reason for this acquisition is that Griffith, being a 100-year-old brand that is broadly recognized as a premier fuel and service provider in its territories, is an excellent strategic fit for the Partnership. The Griffith acquisition adds scale to the Partnership and leverages our existing fixed cost base, providing access to approximately 50,000 residential and commercial accounts across the Mid-Atlantic region.

The following table summarizes the preliminary fair values and purchase price allocation at the acquisition date, of the assets acquired and liabilities assumed related to the Griffith acquisition as of the Acquisition Date. Given the proximity of this acquisition to the end of the quarter, the allocation of the purchase price is preliminary.


(in thousands)	As of Acquisition Date
Trade accounts receivable (a)	$	46,557
Inventories		5,143
Other current assets		5,459
Property and equipment		17,555
Customer lists, trade names and other intangibles		49,157
Other long term assets		1,778
Current liabilities		(30,089	)

Total net identifiable assets acquired	$	95,560


Total consideration	$	98,698
Less: Total net identifiable assets acquired		95,560

Goodwill	$	3,138

(a)	The gross contractual receivable amount is $48.2 million, and the best estimate at the acquisition date of the contractual cash flows not expected to be collected is $1.7 million.

The total costs of $0.8 million related to this acquisition are included in the Consolidated Statement of Operations under general and administrative expenses for the three and six months ended March 31, 2014.

All of the $3.1 million of goodwill relating to the Griffith acquisition is expected to be deductible for income tax purposes.

Griffith’s operating results are included in the Partnership’s consolidated financial statements starting on the Acquisition Date. Customer lists, other intangibles and trade names are amortized on a straight-line basis over ten to twenty years.

Included in our consolidated statement of operations from the Acquisition Date through March 31, 2014, are Griffith’s sales and net earnings before income taxes of $29.6 million and $1.6 million, respectively.

The following table provides unaudited pro forma results of operations as if the Griffith acquisition had occurred on October 1, 2012, the beginning of fiscal year 2013. The unaudited pro forma results were prepared using Griffith’s current and prior year financial information, reflecting certain adjustments related to the acquisition, such as the elimination of directly attributable acquisition expenses and changes to depreciation and amortization expenses. These pro forma adjustments do not include any potential synergies related to combining the businesses. Accordingly, such pro forma operating results were prepared for comparative purposes only and do not purport to be indicative of what would have occurred had the acquisition been made as of October 1, 2012 or of results that may occur in the future.


	Three Months Ended				Six Months Ended
	March 31,				March 31,
(in thousands)	2014		2013		2014		2013

Total sales	$	979,389	$	889,228	$	1,583,557	$	1,488,846

Net income	$	55,247	$	45,651	$	76,068	$	56,701

8) Goodwill and Intangibles, net

Goodwill

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


Balance as of September 30, 2013	$	201,130
Fiscal year 2014 business combination		3,138

Balance as of March 31, 2014	$	204,268

Intangibles, net

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


	March 31, 2014						September 30, 2013
	Gross						Gross
	Carrying		Accumulated				Carrying		Accumulated
	Amount		Amortization		Net		Amount		Amortization		Net
Customer lists and other intangibles	$	337,168	$	226,269	$	110,899	$	288,011	$	221,221	$	66,790

Amortization expense for intangible assets was $5.0 million for the six months ended March 31, 2014, compared to $4.6 million for the six months ended March 31, 2013. 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	$	11,848
2015	$	13,613
2016	$	13,442
2017	$	12,922
2018	$	12,083

9) Long-Term Debt and Bank Facility Borrowings

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


	March 31, 2014				September 30, 2013
	Carrying				Carrying
	Amount		Fair Value (a)		Amount		Fair Value (a)
8.875% Senior Notes (b)	$	124,515	$	132,813	$	124,460	$	130,000
Revolving Credit Facility Borrowings (c)		165,741		165,741		—		—

Total debt	$	290,256	$	298,554	$	124,460	$	130,000

Total long-term portion of debt	$	124,515	$	132,813	$	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 March 31, 2014. Under the terms of the indenture, these notes permit restricted payments after passing particular financial tests. The Partnership can incur debt up to $100 million for acquisitions and can also pay restricted payments of $22.0 million without passing certain financial tests.

(c)	In 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.

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. 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 March 31, 2014, $165.7 million was outstanding under the revolving credit facility and $55.0 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 March 31, 2014, availability was $97.1 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. This shelf registration expires in July 2014. As of March 31, 2014, no offerings under this shelf registration have occurred.

10) Employee Benefit Plan


	Three Months Ended						Six Months Ended
	March 31,						March 31,
(in thousands)	2014			2013			2014			2013

Components of net periodic benefit cost:
Service cost	$	0		$	0		$	0		$	0
Interest cost		690			620			1,380			1,240
Expected return on plan assets		(776	)		(948	)		(1,552	)		(1,896	)
Net amortization		528			664			1,056			1,328

Net periodic benefit cost	$	442		$	336		$	884		$	672

For the six months ended March 31, 2014, the Partnership contributed $0.9 million and expects to make an additional $1.1 million contribution in fiscal 2014 to fund its pension obligation.

11) Income Taxes

Since Star Gas Partners is organized as a master limited partnership, it is not subject to tax at its entity level for Federal and state income tax purposes. However, Star Gas Partners’ income is derived from its corporate subsidiaries, and these entities do incur Federal and state income taxes relating to their respective corporate subsidiaries, which are reflected in these financial statements. For the corporate subsidiaries of Star Gas Partners, a consolidated Federal income tax return is filed.

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, cash received by Star Gas Partners from its corporate subsidiaries is generally included in the determination of qualified Master Limited Partnership income. All or a portion of such cash could be taxable as dividend income or as a capital gain to the individual partners. This could be the case even if Star Gas Partners used the cash received from its corporate subsidiaries for purposes such as the repurchase of common units rather than distributions to its 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 and six months ended March 31, 2014, and 2013 are as follows (in thousands):


	Three Months Ended				Six Months Ended
	March 31,				March 31,
(in thousands)	2014		2013		2014		2013

Income before income taxes	$	89,289	$	70,796	$	122,132	$	85,465

Current tax expense	$	32,215	$	21,330	$	42,438	$	25,383
Deferred tax expense		4,858		7,787		8,190		8,651

Total tax expense	$	37,073	$	29,117	$	50,628	$	34,034

As of January 1, 2014, Star Acquisitions, Inc., 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 March 31, 2014, 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 March 31, 2015. 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.

12) Supplemental Disclosure of Cash Flow Information


	Six Months Ended
	March 31,
(in thousands)	2014		2013

Cash paid during the period for:
Income taxes, net	$	8,395	$	4,901
Interest	$	7,701	$	7,193
Non-cash financing activities:
Increase in interest expense - amortization of debt discount on 8.875% Senior Note	$	55	$	50

13) 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.

14) 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				Six Months Ended
Basic and Diluted Earnings Per Limited Partner:	March 31,				March 31,
(in thousands, except per unit data)	2014		2013		2014		2013
Net income	$	52,216	$	41,679	$	71,504	$	51,431
Less General Partners’ interest in net income		294		225		403		278

Net income available to limited partners		51,922		41,454		71,101		51,153

Less dilutive impact of theoretical distribution of earnings under FASB ASC 260-10-45-60		9,065		6,993		11,922		7,991

Limited Partner’s interest in net income under FASB ASC 260-10-45-60	$	42,857	$	34,461	$	59,179	$	43,162


Per unit data:
Basic and diluted net income available to limited partners	$	0.90	$	0.69	$	1.24	$	0.85

Less dilutive impact of theoretical distribution of earnings under FASB ASC 260-10-45-60		0.15		0.11		0.21		0.13

Limited Partner’s interest in net income under FASB ASC 260-10-45-60	$	0.75	$	0.58	$	1.03	$	0.72


Weighted average number of Limited Partner units outstanding		57,468		59,837		57,490		60,192

15) Subsequent Events

Quarterly Distribution Declared

In April 2014, we declared a quarterly distribution of $0.0875 per unit, or $0.35 per unit on an annualized basis, on all Common Units with respect to the second quarter of fiscal 2014, payable on May 9, 2014, to holders of record on May 1, 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 Common Unit holders and 10% to the General Partner unit holders (until certain distribution levels are met), subject to the management incentive compensation plan. As a result, $5.0 million will be paid to the Common Unit holders, $0.1 million to the General Partner unit holders (including $0.06 million of incentive distribution as provided in our Partnership Agreement) and $0.06 million to management pursuant to the management incentive compensation plan which provides for certain members of management to receive incentive distributions that would otherwise be payable to the General Partner.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Statement Regarding Forward-Looking Disclosure

This Quarterly Report on Form 10-Q includes “forward-looking statements” which represent our expectations or beliefs concerning future events that involve risks and uncertainties, including those associated with the effect of weather conditions on our financial performance, the price and supply of the products that we sell, the consumption patterns of our customers, our ability to obtain satisfactory gross profit margins, our ability to obtain new customers and retain existing customers, our ability to make strategic acquisitions, the impact of litigation, our ability to contract for our current and future supply needs, natural gas conversions, future union relations and the outcome of current and future union negotiations, the impact of current and future governmental regulations, including environmental, health, and safety regulations, the ability to attract and retain employees, customer credit worthiness, counterparty credit worthiness, marketing plans, general economic conditions and new technology. All statements other than statements of historical facts included in this Report including, without limitation, the statements under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere herein, are forward-looking statements. Without limiting the foregoing, the words “believe,” “anticipate,” “plan,” “expect,” “seek,” “estimate,” and similar expressions are intended to identify forward-looking statements. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to be correct and actual results may differ materially from those projected as a result of certain risks and uncertainties. These risks and uncertainties include, but are not limited to, those set forth under the heading “Risk Factors” and “Business Strategy” in our Annual Report on Form 10-K (the “Form 10-K”) for the fiscal year ended September 30, 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. 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 through 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		2.89		3.28		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 the Partnership 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 six months ended March 31, 2014.

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. Beginning July 1, 2014, the states of New Jersey, Rhode Island, Connecticut, Vermont and Massachusetts will require the use of ultra low sulfur home heating oil similar to the New York State requirement.

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.

Griffith Acquisition

On March 4, 2014, the Partnership completed the acquisition of Griffith Energy Services, Inc. (“Griffith”) of Columbia, Maryland from Central Hudson Enterprises Corporation. The Partnership purchased 100% of the stock of Griffith for $98.7 million, consisting of $69.9 million paid for the long term assets and $28.8 million paid for estimated working capital (net of $4.2 million of cash acquired). The estimated working capital is subject to a final post closing adjustment. In addition, the Partnership issued $8.5 million in letters of credit for supply and insurance purposes. There was no long-term debt assumed in the acquisition. The business reason for this acquisition is that Griffith, being a 100-year-old brand that is broadly recognized as a premier fuel and service provider in its territories, is an excellent strategic fit for the Partnership. The Griffith acquisition adds scale to the Partnership and leverages our existing fixed cost base, providing access to approximately 50,000 residential and commercial accounts across the Mid-Atlantic region. For Griffith’s fiscal year ended December 31, 2013, Griffith sold 78.4 million gallons of petroleum products including 29.0 million gallons of home heating oil, 0.9 million gallons of propane and 48.5 million gallons of motor fuel.

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.

Income Taxes

Net Operating Loss Carry Forwards

The Partnership and its corporate subsidiaries file Federal and state income tax returns on a calendar year basis. As of January 1, 2014, our Federal Net Operating Loss carry forwards (“NOLs”) were 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 basis. The amounts below are based on our September 30 fiscal year and are reflective of fixed assets additions and acquisitions up to March 31, 2014, including the Griffith acquisition.

Estimated Depreciation and Amortization Expense


(in thousands) Fiscal Year	Book		Tax
2014	$	22,834	$	34,232
2015		24,455		33,206
2016		22,712		26,022
2017		21,013		18,208
2018		18,849		14,701
2019		15,633		11,642

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.

Income Taxes—Election to be Taxed as an Association or “C Corporation”

The Partnership is evaluating whether to make certain elections for Federal and State tax purposes to both better rationalize our tax reporting structure and to reduce costs.

The production of the Partnership’s K-1 forms is an expensive, time consuming and administratively intensive process. Due to our existing tax structure, our unit holders typically do not receive the tax benefits normally associated with owning units in a publicly traded master limited partnership, as the source of much of the Partnership’s income is from corporations below the Partnership and is subject to corporate level income taxes. Certain cash transfers from the corporations to the Partnership are generally treated as dividends, and may be taxable to the unit holders regardless as to whether the Partnership actually distributes any cash to them. For example, cash sent by the corporate subsidiary to the Partnership for unit repurchases may be treated as dividend income to all our unit holders.

If such an election is made, we would still remain a publicly traded partnership for legal and governance purposes. For income tax purposes, our unit holders would be treated as owning stock in a corporation rather than being partners in a partnership. By making certain elections, the resulting complexities from cash movements will be reduced and certain administrative costs eliminated.

We are beginning to evaluate the income tax consequences to our unit holders of making these elections. In considering whether or not to make them, we also intend to consider the extent to which our general partner would have interests that differ from the interests of our common unit holders and whether such differences would adversely affect our common unit holders

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


	Six Months Ended March 31, 2014						Fiscal Year Ended 2013							Fiscal Year Ended 2012
					Net						Net							Net
	Gross Customer				Gain /		Gross Customer				Gain /			Gross Customer				Gain /
	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		16,900		16,700		200		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		42,700		39,400		3,300		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


	Six Months Ended March 31, 2014									Fiscal Year Ended 2013									Fiscal Year Ended 2012
							Net									Net									Net
	Gross Customer						Gain /			Gross Customer						Gain /			Gross Customer						Gain /
	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		4.1	%		4.1	%		0.0	%		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		10.5	%		9.7	%		0.8	%		14.8	%		18.1	%		(3.3	%)		13.4	%		18.3	%		(4.9	%)

During the first half of fiscal 2014, the Partnership increased its account base by 3,300 accounts, net, or 7,000 accounts greater than the first half of fiscal 2013 in which the Partnership lost 3,700 accounts, net. We believe that the colder-than-expected winter positively impacted our gross customer gains and lowered gross customer losses as our competitors could not keep pace with the severe winter conditions. The Partnership cannot predict whether the accounts added during the six months ended March 31, 2014, will continue to purchase our products.

During the first half of fiscal 2014, we lost 1.2% of our home heating oil accounts to natural gas versus 1.2% for the first half of fiscal 2013 and 1.1% for the first half of fiscal 2012. Conversions to natural gas have been 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 March 31, 2014

Compared to the Three Months Ended March 31, 2013

Volume

For the three months ended March 31, 2014, retail volume of home heating oil and propane increased by 23.5 million gallons, or 14.3%, to 187.9 million gallons, compared to 164.4 million gallons for the three months ended March 31, 2013. 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 March 31, 2014, were 14.6% colder than the three months ended March 31, 2013, and 12.3% colder than normal, as reported by the National Oceanic and Atmospheric Administration (“NOAA”). For the twelve months ended March 31, 2014, net customer attrition for the base business was 1.8%. 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 below 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 March 31, 2013		164.4
Acquisitions		4.9
Impact of colder temperatures		23.2
Net customer attrition		(4.4	)
Other		(0.2	)

Change		23.5


Volume - Three months ended March 31, 2014		187.9

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/other customers for the three months ended March 31, 2014, compared to the three months ended March 31, 2013:


	Three Months Ended
Customers	March 31, 2014			March 31, 2013
Residential Variable		40.2	%		42.1	%
Residential Price-Protected		45.7	%		44.1	%
Commercial/Industrial/Other		14.1	%		13.8	%

Total		100.0	%		100.0	%

The Partnership has experienced a shift from our variable pricing plans to our price-protected offerings as customers are seeking surety of price, which may impact our ability to expand our per gallon margins in the future.

Volume of other petroleum products increased by 3.5 million gallons, or 21.3%, to 19.6 million gallons for the three months ended March 31, 2014, compared to 16.1 million gallons for the three months ended March 31, 2013, largely due to the additional volume from the Griffith acquisition.

Product Sales

For the three months ended March 31, 2014, product sales increased $107.1 million, or 14.6%, to $840.0 million, compared to $732.9 million for the three months ended March 31, 2013, due to an increase in total volume of 14.9%.

Installation and Service Sales

For the three months ended March 31, 2014, installation and service sales increased $0.1 million, or 0.2%, to $52.3 million, compared to $52.2 million for the three months ended March 31, 2013, as the additional revenue from acquisitions of $1.7 million was reduced by a decline in the base business of $1.6 million. In the prior year’s comparable period, installation and service billings were favorably impacted by storm Sandy as certain customers heating systems required extensive repair or complete replacement.

Cost of Product

For the three months ended March 31, 2014, cost of product increased $67.8 million, or 11.9%, to $639.6 million, compared to $571.8 million for the three months ended March 31, 2013, due to an increase in total volume of 14.9%.

Gross Profit—Product

The table below calculates the Partnership’s per gallon margins and reconciles product gross profit for home heating oil and propane and other petroleum products. We believe the change in home heating oil and propane margins should be evaluated before the effects of increases or decreases in the fair value of derivative instruments, as we believe that realized per gallon margins should not include the impact of non-cash changes in the market value of hedges before the settlement of the underlying transaction. On that basis, home heating oil and propane margins for the three months ended March 31, 2014, increased by $0.0811 per gallon, or 8.5%, to $1.0353 per gallon, from $0.9542 per gallon during the three months ended March 31, 2013. Over the last four fiscal years, our home heating oil and propane margins have increased by $0.0143 per gallon on average per year. The expansion of the Partnership’s per gallon margin during the three months March 31, 2014 is in excess of the historical annual average by $0.0675 cents per gallon. During this period, the Partnership was able to take advantage of certain market conditions which enabled the Partnership to expand its margins. In addition, numerous snow storms, which drove an increase in operating and service costs, necessitated an increase in selling prices to defray additional operating costs. Going forward, the Partnership cannot predict whether the per gallon margins achieved during the three months ended March 31, 2014 are sustainable. Product sales and cost of product include home heating oil, propane, other petroleum products and liquidated damages billings.


	Three Months Ended
	March 31, 2014				March 31, 2013
Home Heating Oil and Propane	Amount (in millions)		Per Gallon		Amount (in millions)		Per Gallon
Volume		187.9				164.4

Sales	$	771.8	$	4.1071	$	676.4	$	4.1145
Cost	$	577.2	$	3.0718	$	519.6	$	3.1603


Gross Profit	$	194.6	$	1.0353	$	156.9	$	0.9542


Other Petroleum Products	Amount (in millions)		Per Gallon		Amount (in millions)		Per Gallon
Volume		19.6				16.1

Sales	$	68.2	$	3.4824	$	56.5	$	3.5025
Cost	$	62.4	$	3.1874	$	52.2	$	3.2369


Gross Profit	$	5.8	$	0.2986	$	4.3	$	0.2656


Total Product	Amount (in millions)				Amount (in millions)
Sales	$	840.0			$	732.9
Cost	$	639.6			$	571.8


Gross Profit	$	200.4			$	161.2

For the three months ended March 31, 2014, total product gross profit increased by $39.2 million to $200.4 million, compared to $161.2 million for the three months ended March 31, 2013 due to an increase in home heating oil and propane volume ($22.4 million), the impact of higher home heating oil and propane margins ($15.2 million) and the additional gross profit from other petroleum products ($1.6 million).

Cost of Installations and Service

For the three months ended March 31, 2014, cost of installation and service increased by $1.7 million, or 3.3%, to $53.0 million, compared to $51.3 million for the three months ended March 31, 2013, due to a $1.6 million increase related to acquisitions and $0.1 million tied to our base business. In the base business, service expenses rose by $1.5 million largely due to the additional costs relating to the colder temperatures. Installation costs in the base business declined by $1.4 million due to the lower level of installation work as the prior year’s comparable period benefitted from storm Sandy.

Total installation costs for the three months ended March 31, 2014 decreased by $0.9 million, or 5.6%, to $14.8 million, compared to $15.7 million in installation costs for the three months ended March 31, 2013 as a decline in the base business of $1.4 million was reduced by an increase from acquisitions of $0.5 million. Installation costs as a percentage of installation sales for the three months ended March 31, 2014 and the three months ended March 31, 2013, were 88.6% and 85.4%, respectively. Service expenses increased to $38.2 million for the three months ended March 31, 2014, or 107.4% of service sales, versus $35.6 million, or 105.4% of service sales, for the three months ended March 31, 2013. We experienced a combined loss from service and installation of $0.8 million for the three months ended March 31, 2014 compared to a combined profit of $0.9 million for the three months ended March 31, 2013. Management views the service and installation department on a combined basis because many overhead functions and direct expenses such as service technician time cannot be separated or precisely allocated to either service or installation billings.

(Increase) Decrease in the Fair Value of Derivative Instruments

During the three months ended March 31, 2014, the change in the fair value of derivative instruments resulted in a $4.1 million charge due to the expiration of certain hedged positions (a $0.2 million credit) and a decrease in market value for unexpired hedges (a $4.3 million charge).

During the three months ended March 31, 2013, the change in the fair value of derivative instruments resulted in a $3.4 million credit due to the expiration of certain hedged positions (a $5.1 million credit) and a decrease in the market value for unexpired hedges (a $1.7 million charge).

Delivery and Branch Expenses

For the three months ended March 31, 2014, delivery and branch expense increased $9.1 million, or 10.9%, to $92.4 million, compared to $83.3 million for the three months ended March 31, 2013, due to higher delivery and branch expenses of $4.6 million from the additional volume sold due to colder temperatures and the Griffith acquisition and $1.2 million of higher marketing costs attributable to the improvement in net customer attrition. In addition, delivery and branch expenses rose by $3.3 million largely due to the increase in volume delivered.

On a cents per gallon basis, delivery and branch expenses for the three months ended March 31, 2014 decreased by $0.0173, or 3.6%, to $0.4601, compared to $0.4774 for the three months ended March 31, 2013, as certain fixed operating expenses were spread over a larger volume base in the three months ended March 31, 2014 versus the three months ended March 31, 2013.

Depreciation and Amortization

For the three months ended March 31, 2014, depreciation and amortization expenses increased by $0.6 million, or 13.8%, to $4.9 million, compared to $4.3 million for the three months ended March 31, 2013. This increase was largely due to the Griffith acquisition.

General and Administrative Expenses

For the three months ended March 31, 2014, general and administrative expenses increased $1.6 million, to $6.4 million, from $4.8 million for the three months ended March 31, 2013, due to higher acquisition-related expenses of $0.6 million and an increase in profit sharing expense of $1.0 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 March 31, 2014, finance charge income was unchanged at $2.2 million, compared to the three months ended March 31, 2013.

Interest Expense, Net

For the three months ended March 31, 2014, interest expense increased $0.3 million, or 6.4%, to $4.3 million compared to $4.0 million for the three months ended March 31, 2013, as the impact from an increase in average working capital borrowings of $75.7 million was slightly offset by a 1.0% decline in short-term borrowing rates from 3.6% to 2.6%.

Amortization of Debt Issuance Costs

For the three months ended March 31, 2014, amortization of debt issuance costs was unchanged at $0.4 million compared to the three months ended March 31, 2013.

Income Tax Expense

For the three months ended March 31, 2014, income tax expense increased by $8.0 million to $37.1 million, from $29.1 million for the three months ended March 31, 2013, due to an increase in income before income taxes of $18.5 million. The Partnership’s effective income tax rate was 41.5% for the three months ended March 31, 2014 compared to 41.1% for the three months ended March 31, 2013.

Net Income

For the three months ended March 31, 2014, net income increased $10.5 million to $52.2 million, from $41.7 million for the three months ended March 31, 2013, due to an increase in pretax income of $18.5 million and an increase in income tax expense of $8.0 million.

Adjusted EBITDA

For the three months ended March 31, 2014, Adjusted EBITDA increased by $26.9 million, or 35.3%, to $103.0 million as the impact of 14.6% colder temperatures, higher home heating oil and propane per gallon margins and acquisitions more than offset the volume decline in the business base attributable to net customer attrition for the twelve months ended March 31, 2014 and other factors and increases in operating and service costs largely attributable to the additional volume and numerous snow storms during the three months ended March 31, 2014.

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

EBITDA and Adjusted EBITDA are calculated as follows:


	Three Months Ended March 31,
(in thousands)	2014			2013

Net income	$	52,216		$	41,679
Plus:
Income tax expense		37,073			29,117
Amortization of debt issuance cost		390			418
Interest expense, net		4,274			4,014
Depreciation and amortization		4,917			4,321

EBITDA (i) (a)		98,870			79,549

(Increase) / decrease in the fair value of derivative instruments		4,105			(3,447	)

Adjusted EBITDA (i) (a)		102,975			76,102

Add / (subtract)
Income tax expense		(37,073	)		(29,117	)
Interest expense, net		(4,274	)		(4,014	)
Provision for losses on accounts receivable		3,682			4,440
Increase in accounts receivables		(132,409	)		(102,170	)
Decrease in inventories		29,286			41,432
Decrease in customer credit balances		(32,306	)		(39,786	)
Change in deferred taxes		4,858			7,787
Change in other operating assets and liabilities		36,700			24,539

Net cash used in operating activities	$	(28,561	)	$	(20,787	)

Net cash used in investing activities	$	(99,929	)	$	(1,261	)

Net cash provided by financing activities	$	58,211		$	18,300

(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;

•

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

•

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

•

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

•

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

•

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

Six Months Ended March 31, 2014

Compared to the Six Months Ended March 31, 2013

Volume

For the six months ended March 31, 2014, retail volume of home heating oil and propane increased by 30.1 million gallons, or 11.5%, to 291.6 million gallons, compared to 261.5 million gallons for the six months ended March 31, 2013. 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 six months ended March 31, 2014 were 11.1% colder than the six months ended March 31, 2013 and 6.7% colder than normal, as reported by the National Oceanic and Atmospheric Administration (“NOAA”). For the twelve months ended March 31, 2014, net customer attrition for the base business was 1.8%. In addition, aside from the impact of colder weather, deliveries of home heating oil and propane were greater in the six months ended March 31, 2014 than the six months ended March 31, 2013 due to the impact of Sandy on deliveries for the three months ended March 31, 2013. 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 - Six months ended March 31, 2013		261.5
Acquisitions		5.3
Impact of colder temperatures		28.0
Net customer attrition		(6.9	)
Other		3.7

Change		30.1


Volume -Six months ended March 31, 2014		291.6

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/other customers for the six months ended March 31, 2014 compared to the six months ended March 31, 2013:


	Six Months Ended
Customers	March 31, 2014			March 31, 2013
Residential Variable		40.3	%		42.1	%
Residential Price-Protected		45.6	%		43.9	%
Commercial/Industrial/Other		14.1	%		14.0	%

Total		100.0	%		100.0	%

The Partnership has experienced a shift from our variable pricing plans to our price-protected plans as customers are seeking surety of price which may impact our per gallon margins in the future.

Volume of other petroleum products increased by 1.7 million gallons, or 5.2%, to 34.6 million gallons for the six months ended March 31, 2014, compared to 32.9 million gallons for the six months ended March 31, 2013, largely due to the additional volume from the Griffith acquisition of 3.4 million gallons, partially offset by a decline in the base business of 1.7 million gallons. In the prior year’s comparable period, the Partnership experienced an increase in motor fuel demand as a result of storm Sandy.

Product Sales

For the six months ended March 31, 2014, product sales increased $115.9 million, or 9.8%, to $1.3 billion, compared to $1.2 billion for the six months ended March 31, 2013, primarily due to an increase in total volume of 10.8%.

Installation and Service Sales

For the six months ended March 31, 2014, installation and service sales decreased $4.7 million, or 4.1%, to $109.5 million, compared to $114.2 million for the six months ended March 31, 2013, as additional revenue from acquisitions of $2.0 million was more than offset by a decrease in the base business of $6.7 million. In the prior year’s comparable period installation and service billings were favorably impacted by Sandy-related demand.

Cost of Product

For the six months ended March 31, 2014, cost of product increased $69.7 million, or 7.5%, to $998.1 million, compared to $928.4 million for the six months ended March 31, 2013, largely due to an increase in total volume of 10.8%.

Gross Profit—Product

The table below calculates the Partnership’s per gallon margins and reconciles product gross profit for home heating oil and propane and other petroleum products. We believe the change in home heating oil and propane margins should be evaluated before the effects of increases or decreases in the fair value of derivative instruments, as we believe that realized per gallon margins should not include the impact of non-cash changes in the market value of hedges before the settlement of the underlying transaction. On that basis, home heating oil and propane margins for the six months ended March 31, 2014, increased by $0.0598 per gallon, or 6.3%, to $1.0131 per gallon, from $0.9533 per gallon during the six months ended March 31, 2013. Over the last four fiscal years, our home heating oil and propane margins have increased by $0.0143 cents per gallon on average per year. The expansion of the Partnerships margins during the six months March 31, 2014 is in excess of the historical average by $0.0452 cents per gallon. During this period, the Partnership was able to take advantage of certain market conditions which enabled the Partnership to expand its margins. In addition, numerous snow storms, which drove an increase in operating and service costs, necessitated an increase in selling prices to defray additional operating costs. Going forward, the Partnership cannot predict whether the per gallon margins achieved during the six months ended March 31, 2014 are sustainable. Product sales and cost of product include home heating oil, propane, other petroleum products and liquidated damages billings.


	Six Months Ended
	March 31, 2014				March 31, 2013
Home Heating Oil and Propane	Amount (in millions)		Per Gallon		Amount (in millions)		Per Gallon
Volume		291.6				261.5

Sales	$	1,185.4	$	4.0647	$	1,071.0	$	4.0955
Cost	$	890.0	$	3.0516	$	821.7	$	3.1422


Gross Profit	$	295.5	$	1.0131	$	249.3	$	0.9533


Other Petroleum Products	Amount (in millions)		Per Gallon		Amount (in millions)		Per Gallon
Volume		34.6				32.9

Sales	$	117.9	$	3.4077	$	116.4	$	3.5368
Cost	$	108.2	$	3.1264	$	106.7	$	3.2415


Gross Profit	$	9.7	$	0.2813	$	9.7	$	0.2953


Total Product	Amount (in millions)				Amount (in millions)
Sales	$	1,303.3			$	1,187.4
Cost	$	998.1			$	928.4


Gross Profit	$	305.2			$	259.0

For the six months ended March 31, 2014, total product gross profit increased by $46.2 million to $305.2 million, compared to $259.0 million for the six months ended March 31, 2013, due to an increase in home heating oil and propane volume ($28.7 million) and the impact of higher home heating oil and propane margins ($17.5 million).

Cost of Installations and Service

For the six months ended March 31, 2014, cost of installation and service decreased by $2.1 million, or 1.9%, to $106.5 million, compared to $108.6 million for the six months ended March 31, 2013, as a $1.9 million increase related to acquisitions was more than offset by a $4.0 million reduction in our base business. While service costs rose in the base business due to the additional service costs associated with 11.1% colder temperatures, the prior year’s period included the additional costs from Sandy-related installation and repair work.

Installation costs for the six months ended March 31, 2014, decreased by $4.3 million, or 11.3%, to $34.1 million, compared to $38.4 million in installation costs for the six months ended March 31, 2013 as a decline in the base business of $5.0 million was reduced by an increase from acquisitions of $0.6 million. Installation costs as a percentage of installation sales for the six months ended March 31, 2014 and the six months ended March 31, 2013 were 85.4% and 84.1%, respectively. Service expenses increased to $72.4 million for the six months ended March 31, 2014, or 104.0% of service sales, versus $70.2 million, or 102.3% of service sales, for the six months ended March 31, 2013. We achieved a combined profit from service and installation of $3.0 million for the six months ended March 31, 2014, compared to a combined profit of $5.7 million for the six months ended March 31, 2013. This decline of $2.7 million was due to lower service and installation work from storm Sandy and the increase in service costs resulting from the colder temperatures. Management views the service and installation department on a combined basis because many overhead functions and direct expenses such as service technician time cannot be separated or precisely allocated to either service or installation billings.

(Increase) Decrease in the Fair Value of Derivative Instruments

During the six months ended March 31, 2014, the change in the fair value of derivative instruments resulted in a $1.4 million credit due to the expiration of certain hedged positions (a $5.3 million credit) and a decrease in market value for unexpired hedges (a $3.9 million charge).

During the six months ended March 31, 2013, the change in the fair value of derivative instruments resulted in a $4.5 million charge due to the expiration of certain hedged positions (a $0.6 million charge) and a decrease in the market value for unexpired hedges (a $3.9 million charge). In addition, delivery and branch expenses were impacted by the numerous provisions in our footprint which created delivery inefficiencies.

Delivery and Branch Expenses

For the six months ended March 31, 2014, delivery and branch expense increased $9.1 million, or 6.0%, to $160.8 million, compared to $151.7 million for the six months ended March 31, 2013, due to higher delivery and branch expenses of $4.6 million from the additional volume sold due to colder temperatures and the Griffith acquisition, higher sales and marketing expenses of $1.6 million related to the improved net customer attrition and $2.9 million of additional costs largely due to the increase in volume.

On a cents per gallon basis, delivery and branch expenses for the six months ended March 31, 2014, decreased $0.0234, or 4.4%, to $0.5092, compared to $0.5326 for the six months ended March 31, 2013, as certain fixed operating expenses were spread over a larger volume base in the six months ended March 31, 2014 versus the six months ended March 31, 2013.

Depreciation and Amortization

For the six months ended March 31, 2014, depreciation and amortization expenses increased by $0.6 million, or 6.9%, to $9.3 million, compared to $8.7 million for the six months ended March 31, 2013 largely due to the Griffith acquisition.

General and Administrative Expenses

For the six months ended March 31, 2014, general and administrative expenses increased $2.6 million, or 28.1%, to $11.9 million, from $9.3 million for the six months ended March 31, 2013, primarily due to higher acquisition-related expenses of $0.8 million and an increase in profit sharing expense of $1.2 million.

Finance Income Charge

For the six months ended March 31, 2014, finance charge income decreased $0.1 million to $3.2 million, compared to $3.3 million for the six months ended March 31, 2013.

Interest Expense, Net

For the six months ended March 31, 2014, interest expense increased $0.5 million, or 6.3%, to $7.9 million compared to the $7.4 million for the six months ended March 31, 2013 as the impact from an increase in average working capital borrowings of $49.5 million was reduced by a 0.9% decline in short-term borrowing rates from 3.7% to 2.8%.

Amortization of Debt Issuance Costs

For the six months ended March 31, 2014, amortization of debt issuance costs decreased by $0.1 million to $0.8 million, compared to $0.9 million for the six months ended March 31, 2013.

Income Tax Expense

For the six months ended March 31, 2014, income tax expense increased by $16.6 million to $50.6 million from $34.0 million for the six months ended March 31, 2013, due to an increase in pretax income of $36.7 million and an increase in the effective income tax rate. The Partnership’s effective tax rate was 41.5% for the six months ended March 31, 2014 versus 39.8% for the six months ended March 31, 2013. The increase in the 2014 income tax rate compared to the 2013 rate was primarily due to the recording in the six months ended March 31, 2013 of a $1.0 million deferred tax benefit related to an increase in prospective tax deductions.

Net Income

For the six months ended March 31, 2014, net income increased $20.1 million to $71.5 million, from $51.4 million for the six months ended March 31, 2013, as the increase in pretax income of $36.7 million was greater than the increase in income tax expense of $16.6 million.

Adjusted EBITDA

For the six months ended March 31, 2014, Adjusted EBITDA increased by $31.8 million, or 29.7%, to $138.8 million as the impact 11.1% colder temperatures, higher home heating oil and propane per gallon margins and acquisitions more than offset the volume decline in the base business attributable to net customer attrition for the twelve months ended March 31, 2014 and other factors, the favorable impact of storm Sandy on motor fuel sales and service and installation revenue in the prior year’s comparable period and higher operating and service costs largely attributable to the colder temperatures and the numerous snow storms during the six months ended March 31, 2014.

EBITDA and Adjusted EBITDA are calculated as follows:


	Six Months Ended March 31,
(in thousands)	2014			2013
Net income	$	71,504		$	51,431
Plus:
Income tax expense		50,628			34,034
Amortization of debt issuance cost		811			910
Interest expense, net		7,897			7,431
Depreciation and amortization		9,276			8,679

EBITDA (i) (a)		140,116			102,485

(Increase) / decrease in the fair value of derivative instruments		(1,353	)		4,518

Adjusted EBITDA (i) (a)		138,763			107,003

Add / (subtract)
Income tax expense		(50,628	)		(34,034	)
Interest expense, net		(7,897	)		(7,431	)
Provision for losses on accounts receivable		4,478			6,203
Increase in accounts receivables		(240,013	)		(208,565	)
Decrease in inventories		13,146			5,749
Decrease in customer credit balances		(52,425	)		(62,389	)
Change in deferred taxes		8,190			8,651
Change in other operating assets and liabilities		64,686			43,444

Net cash used in operating activities	$	(121,700	)	$	(141,369	)

Net cash used in investing activities	$	(102,850	)	$	(2,093	)

Net cash provided by financing activities	$	152,448		$	45,939

(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;

•

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 six months ended March 31, 2014, cash used in operating activities was $121.7 million, or $19.7 million less than cash used in operating activities for the six months ended March 31, 2013 of $141.4 million. Cash generated from operations in fiscal 2014 increased by $12.5 million largely due to the impact of colder weather, while cash used to finance accounts receivable, including customers on our budget payment plans, increased by $21.5 million. As of March 31, 2014 (excluding the recently completed Griffith acquisition), days sales outstanding were 36.0 days compared to 34.5 days as of March 31, 2013, and 31.0 days as of March 31, 2012. However, to take advantage of market conditions at September 30, 2013, the Partnership had increased inventory quantities by the beginning of fiscal 2014 to a much greater extent than by the beginning of fiscal 2013. As a result, cash used to finance inventory purchases was $7.4 million less during the six months ended March 31, 2014 than the six months ended March 31, 2013. In addition, 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 $9.0 million more for the six months ended March 31, 2014 than the prior year’s comparable period. 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 accruals and payments, including income taxes, insurance and amounts due under the Partnership’s profit sharing plan provided $12.4 million more cash for the six months ended March 31, 2014 compared to the six months ended March 31, 2013.

Investing Activities

Our capital expenditures for the six months ended March 31, 2014 totaled $5.0 million, as we invested in computer hardware and software ($0.8 million), refurbished certain physical plants ($0.9 million), expanded our propane operations ($2.1 million) and made additions to our fleet and other equipment ($1.2 million). We also completed the Griffith acquisition for $98.7 million and allocated $52.3 million of the gross purchase price to intangible assets (including $3.1 million to goodwill), $17.6 million to fixed assets, and $28.8 million to estimated working capital, net of cash acquired of $4.2 million.

Our capital expenditures for the six months ended March 31, 2013 totaled $2.1 million, as we invested in computer hardware and software ($0.4 million), refurbished certain physical plants ($0.3 million), expanded our propane operations ($1.0 million) and made additions to our fleet and other equipment ($0.4 million).

Financing Activities

During the six months ended March 31, 2014, we borrowed $195.5 million under our revolving credit facility and repaid $29.7 million. We also paid distributions of $9.48 million to our Common Unit holders, $0.14 million to our General Partner unit holders (including $0.10 million of incentive distributions as provided in our Partnership Agreement) and repurchased 0.25 million units for $1.3 million in connection with our unit repurchase plan. We extended our bank facilities and paid $2.4 million in fees.

During the six months ended March 31, 2013, we borrowed $111.5 million under our credit facility and subsequently repaid $50.5 million. We also paid distributions of $9.37 million to our Common Unit holders, $0.11 million to our General Partner unit holders (including $0.07 million of incentive distributions as provided in our Partnership Agreement) and repurchased 1.3 million units for $5.6 million in connection with our unit repurchase plan.

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 March 31, 2014, ($13.0 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 markets are receptive, we may seek to offer and sell debt or equity securities in public or private offerings.

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 (see Note 9(c)), 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 March 31, 2014 there were $165.7 million in borrowings under our revolving credit facility and $55.0 million in letters of credit 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 March 31, 2014, Availability, as defined in the revolving credit facility agreement, was $97.1 million and the fixed charge coverage ratio for the twelve months ended March 31, 2014 was in excess of 1.1.

Maintenance capital expenditures for the remainder of fiscal 2014 are estimated to be approximately $4.0 to $4.5 million, excluding the capital requirements for leased fleet. In addition, we plan to invest an estimated $1.3 million in our propane operations. Distributions during the remainder of fiscal 2014 at the current quarterly level of $0.0875 per unit (subject to the Board’s quarterly determination of the amount of Available Cash), will aggregate approximately $10.1 million to Common Unit holders, $0.172 million to our General Partner (including $0.128 million of incentive distribution as provided in our Partnership Agreement) and $0.128 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 $1.1 million for the remainder of fiscal 2014.

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.

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

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

At March 31, 2014, we had outstanding borrowings totaling $290.3 million, of which approximately $165.7 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 $1.0 million.

We also use derivative financial instruments to manage our exposure to market risk related to changes in the current and future market price of home heating oil. The value of market sensitive derivative instruments is subject to change as a result of movements in market prices. Sensitivity analysis is a technique used to evaluate the impact of hypothetical market value changes. Based on a hypothetical ten percent increase in the cost of product at March 31, 2014, the fair market value of these outstanding derivatives would increase by $8.3 million to a value of $5.4 million; and conversely a hypothetical ten percent decrease in the cost of product would decrease the fair market value of these outstanding derivatives by $3.1 million to a negative value of $(6.0) million.

Item 4.

Controls and Procedures

a) Evaluation of disclosure controls and procedures.

The General Partner’s principal executive officer and its principal financial officer evaluated the effectiveness of the Partnership’s disclosure controls and procedures (as that term is defined in Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended) as of March 31, 2014. Based on that evaluation, such principal executive officer and principal financial officer concluded that the Partnership’s disclosure controls and procedures were effective as of March 31, 2014 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.

On March 4, 2014, the Partnership completed the acquisition of Griffith Energy Services, Inc. (“Griffith”). The Partnership is in the early stages of integrating Griffith. The Partnership is analyzing, evaluating and, where necessary, will implement changes in controls and procedures relating to the Griffith business as integration proceeds. As a result, this process may result in additions or changes to our internal control over financial reporting. Otherwise, there was no change in the Partnership’s internal control over financial reporting during the Partnership’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect the Partnership’s internal control over financial reporting.

c) The General Partner and the Partnership believe that a controls system, no matter how well designed and operated, cannot provide absolute assurance that the objectives of the controls system are met, and no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within a Partnership have been detected. Therefore, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Our disclosure controls and procedures are designed to provide such reasonable assurances of achieving our desired control objectives, and the principal executive officer and principal financial officer of our general partner have concluded, as of March 31, 2014, 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

Not applicable.

Item 6.

Exhibits

(a)	Exhibits Included Within:



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

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

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

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

101		The following materials from the Star Gas Partners, L.P. Quarterly Report on Form 10-Q for the quarter ended March 31, 2014 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)	May 7, 2014

Signature	Title	Date


/s/ Richard G. Oakley Richard G. Oakley	Vice President - Controller Kestrel Heat LLC (Principal Accounting Officer)	May 7, 2014