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 June 30, 2013

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

For the transition period from to

Commission File Number: 001-14129

STAR GAS PARTNERS, L.P.

(Exact name of registrants as specified in its charters)


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

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

(203) 328-7310

(Registrant’s telephone number, including area code)

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

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

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

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

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

At July 31, 2013, the registrant had 57,980,850 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 June 30, 2013 (unaudited) and September 30, 2012		3
Condensed Consolidated Statements of Operations (unaudited) for the three and nine months ended June 30, 2013 and June 30, 2012		4
Condensed Consolidated Statements of Comprehensive Income (unaudited) for the three and nine months ended June 30, 2013 and June 30, 2012		5
Condensed Consolidated Statement of Partners’ Capital (unaudited) for the nine months ended June 30, 2013		6
Condensed Consolidated Statements of Cash Flows (unaudited) for the nine months ended June 30, 2013 and June 30, 2012		7
Notes to Condensed Consolidated Financial Statements (unaudited)		8-17
Item 2—Management’s Discussion and Analysis of Financial Condition and Results of Operations		18-37
Item 3—Quantitative and Qualitative Disclosures About Market Risk		38
Item 4—Controls and Procedures		38

Part II Other Information:
Item 1—Legal Proceedings		39
Item 1A—Risk Factors		39
Item 2—Unregistered Sales of Equity Securities and Use of Proceeds		39
Item 6—Exhibits		40
Signatures		41

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS


(in thousands)	June 30, 2013			September 30, 2012
	(unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	44,382		$	108,091
Receivables, net of allowance of $11,225 and $6,886, respectively		152,558			88,267
Inventories		49,084			47,465
Fair asset value of derivative instruments		—			5,004
Current deferred tax assets, net		18,425			25,844
Prepaid expenses and other current assets		22,545			26,848

Total current assets		286,994			301,519


Property and equipment, net		49,673			52,608
Goodwill		201,119			201,103
Intangibles, net		68,464			74,712
Deferred charges and other assets, net		7,883			9,405

Total assets	$	614,133		$	639,347


LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Accounts payable	$	15,122		$	22,583
Fair liability value of derivative instruments		4,081			453
Accrued expenses and other current liabilities		98,544			78,518
Unearned service contract revenue		41,436			40,799
Customer credit balances		33,335			85,976

Total current liabilities		192,518			228,329


Long-term debt		124,434			124,357
Long-term deferred tax liabilities, net		6,120			8,436
Other long-term liabilities		14,293			18,080

Partners’ capital
Common unitholders		302,208			286,819
General partner		151			97
Accumulated other comprehensive loss, net of taxes		(25,591	)		(26,771	)

Total partners’ capital		276,768			260,145

Total liabilities and partners’ capital	$	614,133		$	639,347

See accompanying notes to condensed consolidated financial statements.

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS


	Three Months Ended June 30,						Nine Months Ended June 30,
(in thousands, except per unit data - unaudited)	2013			2012			2013			2012

Sales:
Product	$	208,862		$	181,751		$	1,396,281		$	1,172,628
Installations and service		53,662			50,725			167,907			150,914

Total sales		262,524			232,476			1,564,188			1,323,542
Cost and expenses:
Cost of product		163,515			146,034			1,091,918			921,931
Cost of installations and service		44,102			39,892			152,661			136,617
(Increase) decrease in the fair value of derivative instruments		1,910			11,225			6,428			1,362
Delivery and branch expenses		53,798			46,760			205,507			176,230
Depreciation and amortization expenses		4,328			4,608			13,007			12,066
General and administrative expenses		4,557			4,008			13,809			13,927

Operating income (loss)		(9,686	)		(20,051	)		80,858			61,409
Interest expense		(3,547	)		(3,435	)		(10,998	)		(10,716	)
Interest income		1,696			1,538			4,978			3,474
Amortization of debt issuance costs		(415	)		(486	)		(1,325	)		(1,145	)

Income (loss) before income taxes		(11,952	)		(22,434	)		73,513			53,022
Income tax expense (benefit)		(4,364	)		(10,645	)		29,670			21,398

Net income (loss)	$	(7,588	)	$	(11,789	)	$	43,843		$	31,624

General Partner’s interest in net income (loss)		(41	)		(62	)		237			166

Limited Partners’ interest in net income (loss)	$	(7,547	)	$	(11,727	)	$	43,606		$	31,458



Basic and Diluted income (loss) per Limited Partner Unit (1)	$	(0.13	)	$	(0.19	)	$	0.63		$	0.46


Weighted average number of Limited Partner units outstanding:
Basic and Diluted		59,370			61,024			59,918			62,236

(1)	See Note 14 - Earnings (Loss) 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 June 30,						Nine Months Ended June 30,
(in thousands - unaudited)	2013			2012			2013			2012

Net income (loss)	$	(7,588	)	$	(11,789	)	$	43,843		$	31,624

Other comprehensive income:
Unrealized gain on pension plan obligation (1)		664			688			1,992			2,064
Tax effect of unrealized gain on pension plan		(270	)		(281	)		(812	)		(842	)

Total other comprehensive income		394			407			1,180			1,222


Total comprehensive income (loss)	$	(7,194	)	$	(11,382	)	$	45,023		$	32,846

(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)	Common			General Partner		Common			General Partner			Accum. Other Comprehensive Income (Loss)			Total Partners’ Capital
Balance as of September 30, 2012		61,002			326	$	286,819		$	97		$	(26,771	)	$	260,145

Net income		—			—		43,606			237			—			43,843
Unrealized gain on pension plan obligation (1)		—			—		—			—			1,992			1,992
Tax effect of unrealized gain on pension plan		—			—		—			—			(812	)		(812	)
Distributions		—			—		(14,277	)		(183	)		—			(14,460	)
Retirement of units (2)		(3,022	)		—		(13,940	)		—			—			(13,940	)

Balance as of June 30, 2013 (unaudited)		57,980			326	$	302,208		$	151		$	(25,591	)	$	276,768

(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


	Nine Months Ended June 30,
(in thousands - unaudited)	2013			2012

Cash flows provided by (used in) operating activities:
Net income	$	43,843		$	31,624

Adjustment to reconcile net income to net cash provided by (used in) operating activities:
(Increase) decrease in fair value of derivative instruments		6,428			1,362
Depreciation and amortization		14,332			13,211
Provision for losses on accounts receivable		7,814			6,864
Change in deferred taxes		4,292			13,657
Changes in operating assets and liabilities:
Increase in receivables		(71,929	)		(21,831	)
(Increase) decrease in inventories		(1,585	)		45,067
Decrease in other assets		6,452			9,203
Decrease in accounts payable		(7,461	)		(2,010	)
Decrease in customer credit balances		(52,719	)		(15,697	)
(Increase) decrease in other current and long-term liabilities		18,903			(351	)

Net cash provided by (used in) operating activities		(31,630	)		81,099


Cash flows provided by (used in) investing activities:
Capital expenditures		(3,133	)		(3,536	)
Proceeds from sales of fixed assets		133			357
Acquisitions		(644	)		(38,336	)

Net cash used in investing activities		(3,644	)		(41,515	)


Cash flows provided by (used in) financing activities:
Revolving credit facility borrowings		111,542			86,252
Revolving credit facility repayments		(111,542	)		(86,252	)
Distributions		(14,460	)		(14,739	)
Unit repurchases		(13,940	)		(19,555	)
Deferred charges		(35	)		(847	)

Net cash used in financing activities		(28,435	)		(35,141	)


Net increase (decrease) in cash and cash equivalents		(63,709	)		4,443

Cash and cash equivalents at beginning of period		108,091			86,789

Cash and cash equivalents at end of period	$	44,382		$	91,232

See accompanying notes to condensed consolidated financial statements.

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

1) Partnership Organization

Star Gas Partners, L.P. (“Star Gas Partners,” the “Partnership,” “we,” “us,” or “our”) is a home heating oil and propane distributor and services provider with one reportable operating segment that principally provides services to residential and commercial customers to heat their homes and buildings. Star Gas Partners is a master limited partnership, which at June 30, 2013, had outstanding 58.0 million common units (NYSE: “SGU”), representing the 99.44% limited partner interest in Star Gas Partners, and 0.3 million general partner units, representing the 0.56% general partner interest in Star Gas Partners.

The Partnership is organized as follows:

•

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

•

The Partnership’s operations are conducted through Petro Holdings, Inc. and its subsidiaries (“Petro”). Petro is a Minnesota corporation that is an indirect wholly-owned subsidiary of the Partnership. Petro is subject to Federal and state corporation income taxes. Petro is a Northeast and Mid-Atlantic region retail distributor of home heating oil and propane that at June 30, 2013 served approximately 407,000 full-service residential and commercial home heating oil and propane customers. Petro also sold home heating oil, gasoline and diesel fuel to approximately 53,600 customers on a delivery only basis. In addition, Petro installed, maintained, and repaired heating and air conditioning equipment for its customers, and provided ancillary home services, including home security and plumbing, to approximately 11,600 customers.

•

Star Gas Finance Company is a 100% owned subsidiary of the Partnership. Star Gas Finance Company serves as the co-issuer, jointly and severally with the Partnership, of its $125 million (excluding discount) 8.875% Senior Notes outstanding at June 30, 2013, that are due 2017. The Partnership is dependent on distributions, including inter-company interest payments from its subsidiaries, to service the Partnership’s debt obligations. The distributions from the Partnership’s subsidiaries are not guaranteed and are subject to certain loan restrictions. Star Gas Finance Company has nominal assets and conducts no business operations. (See Note 8—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 nine month period ended June 30, 2013 and June 30, 2012 are not necessarily indicative of the results to be expected for the full year.

These interim financial statements of the Partnership have been prepared in accordance with U.S. Generally Accepted Accounting Principles (“GAAP”) for interim financial information and Rule 10-01 of Regulation S-X of the U.S. Securities and Exchange Commission and should be read in conjunction with the financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended September 30, 2012.

Comprehensive Income (Loss)

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

Recent Accounting Pronouncements

In December 2011, the Financial Accounting Standards Board (“FASB”) issued ASU No. 2011-11, Disclosures about Offsetting Assets and Liabilities. This standard requires an entity to disclose information about offsetting and related arrangements to enable users of financial statements to understand the effect of those arrangements on its financial position. The amendments require added disclosures about financial instruments and derivative instruments that are either (1) offset in accordance with other GAAP or (2) subject to an enforceable master netting arrangement or similar agreement, regardless of whether they are offset on the balance sheet. This new guidance is effective for our annual reporting periods beginning in the first quarter of fiscal year 2014. The adoption of ASU No. 2011-11 will not impact our results of operations or the amount of assets and liabilities reported. We are currently evaluating the impact on our disclosures.

3) Common Unit Repurchase and Retirement

In July 2012, the Board authorized the repurchase of up to 3.0 million of the Partnership’s common units (“Plan III”). 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. In June 2013, the Board authorized the repurchase of 1.15 million additional common units in a private transaction. 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.

In July 2013, the Board authorized an additional 1.9 million common units to be repurchased under its Plan III common unit repurchase plan, restoring the number of units that may yet be repurchased under this program to 3.0 million common units at July 31, 2013.

The Partnership must maintain Availability (as defined in the revolving credit facility agreement) of $61.3 million, 17.5% of the maximum facility size of $350 million (assuming a seasonal advance of $100 million is outstanding) on a historical pro forma and forward-looking basis, and a fixed charge coverage ratio of not less than 1.15 in order to repurchase common units.


(in thousands, except per unit amounts)
Period	Total Number of Units Purchased as Part of a Publicly Announced Plan or Program		Average Price Paid per Unit (a)		Maximum Number of Units that May Yet Be Purchased Under the Program
Plan III - Number of units authorized						3,000
Private transaction - Number of units authorized (b)						1,150

						4,150

Plan III - Fiscal year 2012 total		22	$	4.26		4,128


Plan III - October 2012		39	$	4.28		4,089
Plan III - November 2012		645	$	4.20		3,444
Plan III - December 2012		331	$	4.13		3,113

Plan III - First quarter fiscal year 2013 total		1,015	$	4.18


Plan III - January 2013		91	$	4.25		3,022
Plan III - February 2013		—	$	—		3,022
Plan III - March 2013		219	$	4.40		2,803

Plan III - Second quarter fiscal year 2013 total		310	$	4.36


Plan III - April 2013		161	$	4.74		2,642
Plan III - May 2013		228	$	4.88		2,414
Plan III - June 2013 (b)		1,308	$	4.95		1,106

Plan III - Third quarter fiscal year 2013 total		1,697	$	4.92



Plan III - Nine months fiscal year 2013 total		3,022	$	4.61

(a)	Amounts include repurchase costs.

(b)	June 2013 common unit repurchases include 1.15 million common units acquired in a private transaction.

4) Derivatives and Hedging - Disclosures and Fair Value Measurements

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

To hedge a substantial majority of the purchase price associated with heating oil gallons anticipated to be sold to its price-protected customers as of June 30, 2013, the Partnership held 1.0 million gallons of physical inventory and had bought 4.3 million gallons of swap contracts, 1.3 million gallons of call options, 3.1 million gallons of put options and 47.1 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 June 30, 2013, had bought 27.3 million gallons of future contracts, had sold 34.0 million gallons of future contracts and had sold 4.4 million gallons of future swap contracts. To hedge a majority of its internal fuel usage for fiscal 2013, the Partnership as of June 30, 2013, had bought 2.0 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 June 30, 2012, the Partnership held 1.2 million gallons of physical inventory and had bought 4.8 million gallons of swap contracts, 1.4 million gallons of call options, 4.1 million gallons of put options and 44.6 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 June 30, 2012, had bought 47.0 million gallons of future contracts and had sold 51.5 million gallons of future contracts. To hedge a majority of its internal fuel usage for fiscal 2012, the Partnership as of June 30, 2012, had bought 2.6 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., 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 maintains master netting arrangements with counterparties to help manage the risks, and record derivative positions on a net basis. The Partnership considers counterparty credit risk to be low. At June 30, 2013, the aggregate cash posted as collateral in the normal course of business at counterparties was $0.9 million. Positions with counterparties who are also parties to our revolving credit facility are collateralized under that facility. As of June 30, 2013, $8.0 million of hedge positions were secured under the credit facility.

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

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 June 30, 2013
Commodity contracts	Fair asset and fair liability value of derivative instruments	$	12,015		$	2,529		$	9,486		$	—

Commodity contract assets at June 30, 2013		$	12,015		$	2,529		$	9,486		$	—


Liability Derivatives at June 30, 2013
Commodity contracts	Fair liability and fair asset value of derivative instruments	$	(16,096	)	$	(2,435	)	$	(13,661	)	$	—

Commodity contract liabilities at June 30, 2013		$	(16,096	)	$	(2,435	)	$	(13,661	)	$	—


Asset Derivatives at September 30, 2012
Commodity contracts	Fair asset and fair liability value of derivative instruments	$	15,100		$	1,749		$	13,351		$	—

Commodity contract assets at September 30, 2012		$	15,100		$	1,749		$	13,351		$	—


Liability Derivatives at September 30, 2012
Commodity contracts	Fair liability and fair asset value of derivative instruments	$	(10,549	)	$	(1,898	)	$	(8,651	)	$	—

Commodity contract liabilities at September 30, 2012		$	(10,549	)	$	(1,898	)	$	(8,651	)	$	—


(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 June 30, 2013			Three Months Ended June 30, 2012			Nine Months Ended June 30, 2013			Nine Months Ended June 30, 2012

Commodity contracts	Cost of product (a)	$	2,531		$	359		$	15,951		$	15,683
Commodity contracts	Cost of installations and service (a)	$	(67	)	$	(120	)	$	(401	)	$	(224	)
Commodity contracts	Delivery and branch expenses (a)	$	(43	)	$	4		$	(246	)	$	(87	)

Commodity contracts	(Increase) / decrease in the fair value of derivative instruments	$	1,910		$	11,225		$	6,428		$	1,362

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

5) Inventories

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


	June 30, 2013		September 30, 2012
Product	$	31,135	$	30,786
Parts and equipment		17,949		16,679

Total inventory	$	49,084	$	47,465

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):


	June 30, 2013		September 30, 2012

Property and equipment	$	167,055	$	167,060
Less: accumulated depreciation		117,382		114,452

Property and equipment, net	$	49,673	$	52,608

7) Business Combination

During fiscal 2013, the Partnership acquired a heating oil dealer for an aggregate purchase price of approximately $0.6 million. The gross purchase price was allocated $0.6 million to intangible assets, $0.1 million to fixed assets and reduced by $0.1 million for working capital credits. The operating results of this acquisition has been included in the Partnership’s consolidated financial statements since the date of acquisition, and are not material to the Partnership’s financial condition, results of operations, or cash flows.

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, 2012	$	201,103
Fiscal year 2013 business combination		16

Balance as of June 30, 2013	$	201,119

Consistent with the requirements of FASB ASC 350-10-05 Intangibles - Goodwill and Other, the Partnership has selected August of each year to perform its annual impairment review. Based on our August 31, 2012 annual impairment review, we determined that there was no goodwill impairment. The preparation of this analysis was based upon management’s estimates and assumptions. Future impairment calculations may be affected by actual results that are materially different from projected amounts. To provide for a sensitivity of the discount rates and transaction multiples used, ranges of high and low values are employed in the analysis, with the low values examined to ensure that a reasonably likely change in an assumption would not cause the Partnership to reach a different conclusion.

Intangibles, net

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


	June 30, 2013						September 30, 2012
	Gross Carrying Amount		Accum. Amortization		Net		Gross Carrying Amount		Accum. Amortization		Net
Customer lists and other intangibles	$	287,382	$	218,918	$	68,464	$	286,783	$	212,071	$	74,712

Amortization expense for intangible assets was $6.8 million for the nine months ended June 30, 2013, compared to $6.0 million for the nine months ended June 30, 2012. Total estimated annual amortization expense related to intangible assets subject to amortization, for the fiscal year ending September 30, 2013, and the four succeeding fiscal years ending September 30, is as follows (in thousands):


	Estimated Annual Book Amortization Expense
2013	$	9,142
2014	$	9,110
2015	$	8,974
2016	$	8,804
2017	$	8,284

9) Long-Term Debt and Bank Facility Borrowings

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


	June 30, 2013				September 30, 2012
	Carrying Amount		Fair Value (a)		Carrying Amount		Fair Value (a)
8.875% Senior Notes (b)	$	124,434	$	126,563	$	124,357	$	126,563
Revolving Credit Facility Borrowings (c)		—		—		—		—

Total debt	$	124,434	$	126,563	$	124,357	$	126,563

Total long-term portion of debt	$	124,434	$	126,563	$	124,357	$	126,563

(a)	The Partnership’s fair value estimates of long-term debt are made at a specific point in time, based on Level 2 inputs.

(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 $0.6 million at June 30, 2013. Under the terms of the indenture, these notes permit restricted payments after passing certain financial tests. The Partnership can incur debt up to $100 million for acquisitions and can also pay restricted payments of $22.0 million without passing certain financial tests.

(c)

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

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

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

The Partnership is obligated to meet certain financial covenants under the amended and restated revolving credit facility, including the requirement to maintain at all times either Availability (borrowing base less amounts borrowed and letters of credit issued) of $43.8 million, 12.5% of the maximum facility size, or a fixed charge coverage ratio (as defined in the revolving credit facility agreement) of not less than 1.1, which is calculated based upon Adjusted EBITDA for the trailing twelve months. In order to make acquisitions, the Partnership must maintain Availability of $40 million on a historical pro forma and forward-looking basis. In addition, the Partnership must maintain Availability of $61.3 million, 17.5% of the maximum facility size of $350 million (assuming a seasonal advance of $100 million is outstanding) on a historical pro forma and forward-looking basis, and a fixed charge coverage ratio of not less than 1.15 in order to pay any distributions to unitholders or repurchase common units.

At June 30, 2013, no amount was outstanding under the revolving credit facility and $45.0 million of letters of credit were issued. At September 30, 2012, no amount was outstanding under the revolving credit facility and $42.8 million of letters of credit were issued.

The amended and restated revolving credit facility prohibits certain activities including investments, acquisitions, asset sales, inter-company dividends or distributions (including those needed to pay interest or principal on the 8.875% senior notes), except to the Partnership or a wholly owned subsidiary of the Partnership, if the relevant covenant described above has not been met. The occurrence of an event of default or an acceleration under the amended and restated revolving credit facility would result in the Partnership’s inability to obtain further borrowings under that facility, which could adversely affect its results of operations. Such a default may also restrict the ability of the Partnership to obtain funds from its subsidiaries in order to pay interest or pay down debt. An acceleration under the amended and restated revolving credit facility would result in a default under the Partnership’s other funded debt.

At June 30, 2013, availability was $139.1 million and the Partnership was in compliance with the fixed charge coverage ratio. At September 30, 2012, availability was $179.2 million and the Partnership was in compliance with the fixed charge coverage ratio.

In July 2011, the Partnership’s shelf registration became effective, providing for the sale of up to $250 million in one or more offerings of common units representing limited partnership interests, partnership securities and debt securities; which may be secured or unsecured senior debt securities or secured or unsecured subordinated debt securities. As of June 30, 2013, no offerings under this shelf registration have occurred.

10) Employee Benefit Plan


	Three Months Ended June 30,						Nine Months Ended June 30,
(in thousands)	2013			2012			2013			2012

Components of net periodic benefit cost:
Service cost	$	—		$	—		$	—		$	—
Interest cost		620			714			1,860			2,142
Expected return on plan assets		(948	)		(941	)		(2,844	)		(2,823	)
Net amortization		664			688			1,992			2,064

Net periodic benefit cost	$	336		$	461		$	1,008		$	1,383

For the nine months ended June 30, 2013, the Partnership contributed $2.3 million and expects to make an additional $1.2 million contribution in fiscal 2013 to fund its pension obligation.

11) Income Taxes

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

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

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

The current and deferred income tax expenses for the three and nine months ended June 30, 2013, and 2012 are as follows (in thousands):


	Three Months Ended June 30,						Nine Months Ended June 30,
(in thousands)	2013			2012			2013		2012

Income (loss) before income taxes	$	(11,952	)	$	(22,434	)	$	73,513	$	53,022

Current tax expense (benefit)	$	(5	)	$	(1,372	)	$	25,378	$	7,741
Deferred tax expense (benefit)		(4,359	)		(9,273	)		4,292		13,657

Total tax expense (benefit)	$	(4,364	)	$	(10,645	)	$	29,670	$	21,398

As of the calendar tax year ended December 31, 2012, Star Acquisitions, a wholly-owned subsidiary of the Partnership, had an estimated Federal net operating loss carry forward (“NOLs”) of approximately $10.6 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 June 30, 2013, we had unrecognized income tax benefits totaling $0.8 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 June 30, 2014. Our continuing practice is to recognize interest related to income tax matters as a component of income tax expense. We file U.S. Federal income tax returns and various state and local returns. A number of years may elapse before an uncertain tax position is audited and finally resolved. For our Federal income tax returns we have four tax years subject to examination. In our major state tax jurisdictions of New York, Connecticut, Pennsylvania and New Jersey, we have four, four, four and five tax years, respectively, that are subject to examination. While it is often difficult to predict the final outcome or the timing of resolution of any particular uncertain tax position, based on our assessment of many factors including past experience and interpretation of tax law, we believe that our provision for income taxes reflect the most probable outcome. This assessment relies on estimates and assumptions and may involve a series of complex judgments about future events.

12) Supplemental Disclosure of Cash Flow Information


	Nine Months Ended June 30,
(in thousands)	2013		2012

Cash paid during the period for:
Income taxes, net	$	11,864	$	2,687
Interest	$	13,771	$	13,540
Non-cash financing activities:
Increase in interest expense - amortization of debt discount on 8.875% Senior Note	$	77	$	70

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:


Basic and Diluted Earnings Per Limited Partner: (in thousands, except per unit data)	Three Months Ended June 30,						Nine Months Ended June 30,
	2013			2012			2013		2012
Net income (loss)	$	(7,588	)	$	(11,789	)	$	43,843	$	31,624
Less General Partners’ interest in net income (loss)		(41	)		(62	)		237		166

Net income (loss) available to limited partners		(7,547	)		(11,727	)		43,606		31,458

Less dilutive impact of theoretical distribution of earnings under FASB ASC 260-10-45-60		—			—			5,623		3,141

Limited Partner’s interest in net income (loss) under FASB ASC 260-10-45-60	$	(7,547	)	$	(11,727	)	$	37,983	$	28,317


Per unit data:
Basic and diluted net income (loss) available to limited partners	$	(0.13	)	$	(0.19	)	$	0.73	$	0.51

Less dilutive impact of theoretical distribution of earnings under FASB ASC 260-10-45-60		—			—			0.10		0.05

Limited Partner’s interest in net income (loss) under FASB ASC 260-10-45-60	$	(0.13	)	$	(0.19	)	$	0.63	$	0.46


Weighted average number of Limited Partner units outstanding		59,370			61,024			59,918		62,236

15) Subsequent Events

Quarterly Distribution Declared

In July 2013, we declared a quarterly distribution of $0.0825 per unit, or $0.33 per unit on an annualized basis, on all common units with respect to the third quarter of fiscal 2013, payable on August 13, 2013, to holders of record on August 5, 2013. In accordance with our Partnership Agreement, the amount of distributions in excess of the minimum quarterly distribution of $0.0675, are distributed 90% to the holders of common units and 10% to the holders of the General Partner units (until certain distribution levels are met), subject to the management incentive compensation plan. As a result, $4.8 million will be paid to the common unit holders, $0.1 million to the General Partner (including $0.05 million of incentive distribution as provided in our Partnership Agreement) and $0.05 million to management pursuant to the management incentive compensation plan which provides for certain members of management to receive incentive distributions that would otherwise be payable to the General Partner.

Additional Common Units Authorized for Repurchase Under the Plan III Repurchase Program

Acquisition

In August 2013, the Partnership purchased for cash the customer lists and assets of a home heating oil dealership for approximately $0.7 million, including net working capital credits of $0.1 million.

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, 2012, 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 to 2010. Our calculations of normal weather are based on these published 30 year averages for heating degree days, weighted by volume for the locations where we have existing operations.

Home Heating Oil Price Volatility

In recent years, the wholesale price of home heating oil has been volatile, resulting in increased consumer price sensitivity to heating costs and increased gross customer losses. As a commodity, the price of home heating oil is generally impacted by many factors, including economic and geopolitical forces. The price of home heating oil is closely linked to the price refiners pay for crude oil, which is the principal cost component of home heating oil. The volatility in the wholesale cost of home heating oil, as measured by the New York Mercantile Exchange (“NYMEX”) price per gallon for the fiscal years ending September 30, 2009, through 2013, on a quarterly basis, is illustrated in the following chart:


	Fiscal 2013 *				Fiscal 2012				Fiscal 2011				Fiscal 2010				Fiscal 2009
Quarter Ended	Low		High		Low		High		Low		High		Low		High		Low		High
December 31	$	2.90	$	3.26	$	2.72	$	3.17	$	2.19	$	2.54	$	1.78	$	2.12	$	1.20	$	2.85
March 31		2.86		3.24		2.99		3.32		2.49		3.09		1.89		2.20		1.13		1.63
June 30		2.74		3.09		2.53		3.25		2.75		3.32		1.87		2.35		1.31		1.86
September 30		—		—		2.68		3.24		2.77		3.13		1.92		2.24		1.50		1.96

*	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.

Impact of Warm Weather on Operating Results; Weather Hedge Contract—Fiscal Year 2012

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

Weather Hedge Contract—Fiscal Years 2013, 2014 and 2015

In July 2012, the Partnership entered into a weather hedge contract for the fiscal years 2013, 2014 and 2015, with Swiss Re Financial Products Corporation, under which Star is entitled to receive a payment of $35,000 per heating degree-day shortfall if the total number of heating degree-days in the period covered is less than 92.5% of the ten year average (the “Payment Threshold”). The hedge covers the period from November 1 through March 31, taken as a whole, for each respective fiscal year and has a maximum payout of $12.5 million for each fiscal year. The Partnership did not record any benefit under its weather hedge contract during the nine months ended June 30, 2013.

Per Gallon Gross Profit Margins

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

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

Derivatives

FASB ASC 815-10-05 Derivatives and Hedging requires that derivative instruments be recorded at fair value and included in the consolidated balance sheet as assets or liabilities. To the extent derivative instruments designated as cash flow hedges are effective, as defined under this guidance, changes in fair value are recognized in other comprehensive income until the forecasted hedged item is recognized in earnings. We have elected not to designate our derivative instruments as hedging instruments under this guidance, and as a result, the changes in fair value of the derivative instruments are recognized in our statement of operations. Therefore, we experience volatility in earnings as outstanding derivative instruments are marked to market and non-cash gains and losses are recorded prior to the sale of the commodity to the customer. The volatility in any given period related to unrealized non-cash gains or losses on derivative instruments can be significant to our overall results. However, we ultimately expect those gains and losses to be offset by the cost of product when purchased.

New York State Ultra Low Sulfur Fuel Oil Regulation

On July 1, 2012, new regulations went into effect in New York State (an important area of operations for us) that require the use of ultra low sulfur home heating oil (which is essentially ultra low sulfur diesel fuel with a dye additive). From July 1, 2012 through March 31, 2013, the additional cost of ultra low sulfur home heating oil versus high sulfur home heating oil in New York ranged from between $0.035 and $0.230 cents per gallon. The NYMEX continued to trade only the high sulfur home heating oil hedge contract through March 31, 2013. Effective as of 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. Consequently, there was a nine month period, from July 2012 through March 2013, when the Partnership needed to purchase and sell ultra low sulfur home heating oil for its New York State customers while a contract was not directly available to hedge on the NYMEX. The Partnership

hedged the purchases of ultra low sulfur home heating oil from July 1, 2012 to March 31, 2013, utilizing a NYMEX high sulfur home heating oil contract. Furthermore, due to the change in the specifications of the NYMEX contract in April 2013, the Partnership now has a similar mis-match from April 2013 going forward in its ability to hedge high sulfur home heating oil requirements for purchases and sales in states other than New York. The Partnership has hedged its purchases of high sulfur home heating oil since April 1, 2013, with the new NYMEX ultra low sulfur diesel contracts. From April 1 to June 30, 2013, high sulfur home heating oil was sold at a discount to the NYMEX ultra low sulfur diesel contract of between $0.11 and $0.25 cents per gallon.

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 its price-protected customers, which may impact home heating oil per gallon gross profit margins for these customers.

Income Taxes

Net Operating Loss Carry Forwards

As of December 31, 2012, we estimated that our Federal Net Operating Loss carry forwards (“NOLs”) were $10.6 million, subject to annual limitations of between $1.0 million and $2.2 million on the amount of such losses that can be used.

Book Versus Tax Deductions

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

Estimated Depreciation and Amortization Expense


(in thousands) Fiscal Year	Book		Tax
2013	$	19,019	$	33,098
2014		17,708		28,293
2015		16,191		24,398
2016		14,101		18,601
2017		11,978		11,419

Non-Deductible Partnership Expenses

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

Storm Sandy

On October 29, 2012, storm “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 storm Sandy, 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 storm Sandy. However, since our operations were able to provide uninterrupted service to current and new customers, our sales of diesel fuel for the weeks after the storm increased, as did our service and installation sales, along with the related costs to provide these services.

EBITDA and Adjusted EBITDA (non-GAAP financial measures)

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

•

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

•

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

•

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

•

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

•

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

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

•

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

•

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

•

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

•

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

•

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

Customer Attrition

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

Gross customer gains and gross customer losses


	Nine Months Ended June 30, 2013							Fiscal Year Ended 2012							Fiscal Year Ended 2011
	Gross Customer				Net Attrition			Gross Customer				Net Attrition			Gross Customer				Net Attrition
	Gains		Losses		Net Attrition			Gains		Losses		Net Attrition			Gains		Losses		Net Attrition
First Quarter		26,100		24,400		1,700			25,700		26,600		(900	)		21,900		24,100		(2,200	)
Second Quarter		13,900		19,300		(5,400	)		11,500		19,700		(8,200	)		11,800		17,200		(5,400	)
Third Quarter		7,100		13,600		(6,500	)		7,000		13,700		(6,700	)		6,000		11,400		(5,400	)
Fourth Quarter		—		—		—			13,000		18,200		(5,200	)		15,300		17,100		(1,800	)

Total		47,100		57,300		(10,200	)		57,200		78,200		(21,000	)		55,000		69,800		(14,800	)

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


	Nine Months Ended June 30, 2013									Fiscal Year Ended 2012									Fiscal Year Ended 2011
	Gross Customer						Net Attrition			Gross Customer						Net Attrition			Gross Customer						Net Attrition
	Gains			Losses			Net Attrition			Gains			Losses			Net Attrition			Gains			Losses			Net Attrition
First Quarter		6.3	%		5.9	%		0.4	%		6.2	%		6.4	%		(0.2	%)		5.3	%		5.8	%		(0.5	%)
Second Quarter		3.3	%		4.6	%		(1.3	%)		2.7	%		4.7	%		(2.0	%)		2.8	%		4.1	%		(1.3	%)
Third Quarter		1.7	%		3.3	%		(1.6	%)		1.5	%		3.1	%		(1.6	%)		1.5	%		2.8	%		(1.3	%)
Fourth Quarter		—			—			—			3.0	%		4.1	%		(1.1	%)		3.6	%		4.0	%		(0.4	%)

Total		11.3	%		13.8	%		(2.5	%)		13.4	%		18.3	%		(4.9	%)		13.2	%		16.7	%		(3.5	%)

During the first nine months of fiscal 2013, the Partnership lost 10,200 accounts (net), or 2.5%, of our home heating oil and propane customer base, compared to the first nine months of fiscal 2012, during which the Partnership lost 15,800 accounts (net), or 3.8% of our home heating oil and propane customer base. The improvement of 5,600 accounts was due to an increase in gross customer gains of 2,900 and lower gross customer losses of 2,700. The increase in gains can be attributed to an increase in referrals as well as marketing and advertising related activity. The decrease in losses was mainly due to fewer credit cancellations and price-related losses.

During the first nine months of fiscal 2013, we lost 1.7% of our home heating oil accounts to natural gas versus losses of 1.6% for the first nine months of fiscal 2012, and 1.0% for the first nine months of fiscal 2011. Conversions to natural gas are increasing and we believe this may continue 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 June 30, 2013

Compared to the Three Months Ended June 30, 2012

Volume

For the three months ended June 30, 2013, retail volume of home heating oil and propane increased by 7.6 million gallons, or 21.7%, to 42.7 million gallons, compared to 35.1 million gallons for the three months ended June 30, 2012. For those locations where the Partnership had existing operations during both periods, which we sometimes refer to as the “base business” (i.e., excluding acquisitions), temperatures (measured on a heating degree day basis) for the three months ended June 30, 2013, were 27.4% colder than the three months ended June 30, 2012, and 4.1% warmer than normal, as reported by the National Oceanic and Atmospheric Administration (“NOAA”). For the twelve months ended June 30, 2013, net customer attrition for the base business was 3.7%. 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 product. The impact of 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 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 as follows:


(in millions of gallons)	Heating Oil and Propane
Volume - Three months ended June 30, 2012		35.1
Acquisitions		0.2
Impact of colder temperatures		6.4
Net customer attrition		(1.1	)
Other		2.1

Change		7.6


Volume - Three months ended June 30, 2013		42.7

The following chart sets forth the percentage by volume of total home heating oil sold to residential variable-price customers, residential price-protected customers and commercial/industrial/other customers for the three months ended June 30, 2013, compared to the three months ended June 30, 2012:


	Three Months Ended
Customers	June 30, 2013			June 30, 2012
Residential Variable		39.7	%		41.4	%
Residential Price-Protected		46.9	%		44.1	%
Commercial/Industrial/Other		13.4	%		14.5	%

Total		100.0	%		100.0	%

Product Sales

For the three months ended June 30, 2013, product sales increased $27.1 million, or 14.9%, to $208.9 million, compared to $181.8 million for the three months ended June 30, 2012, due to an increase in total volume of 15.8%.

Installation and Service Sales

For the three months ended June 30, 2013, installation and service sales increased $3.0 million, or 5.8%, to $53.7 million, compared to $50.7 million for the three months ended June 30, 2012, due in part to an increase in plumbing, air conditioning and natural gas related revenues.

Cost of Product

For the three months ended June 30, 2013, cost of product increased $17.5 million, or 12.0%, to $163.5 million, compared to $146.0 million for the three months ended June 30, 2012, as an increase in total volume of 15.8% was reduced by a 3.5% decline in per gallon wholesale product costs.

Gross Profit — Product

The table below calculates the Partnership’s per gallon margins and reconciles product gross profit for home heating oil and propane and other petroleum products. We believe the change in home heating oil and propane margins should be evaluated before the effects of increases or decreases in the fair value of derivative instruments, as we believe that realized per gallon margins should not include the impact of non-cash changes in the market value of hedges before the settlement of the underlying transaction. On that basis, home heating oil and propane margins for the three months ended June 30, 2013, increased by $0.0584 per gallon, or 6.4%, to $0.9780 per gallon, from $0.9196 per gallon during the three months ended June 30, 2012. Product sales and cost of product include home heating oil, propane, other petroleum products and liquidated damages billings.


	Three Months Ended
	June 30, 2013				June 30, 2012
Home Heating Oil and Propane	Amount (in millions)		Per Gallon		Amount (in millions)		Per Gallon
Volume		42.7				35.1

Sales	$	166.6	$	3.9019	$	138.5	$	3.9469
Cost	$	124.8	$	2.9239	$	106.2	$	3.0273


Gross Profit	$	41.7	$	0.9780	$	32.3	$	0.9196


Other Petroleum Products	Amount (in millions)		Per Gallon		Amount (in millions)		Per Gallon
Volume		13.1				13.0

Sales	$	42.3	$	3.2386	$	43.3	$	3.3179
Cost	$	38.7	$	2.9630	$	39.8	$	3.0530


Gross Profit	$	3.6	$	0.2756	$	3.5	$	0.2649


Total Product	Amount (in millions)				Amount (in millions)
Sales	$	208.9			$	181.8
Cost	$	163.5			$	146.0


Gross Profit	$	45.3			$	35.7

For the three months ended June 30, 2013, total product gross profit increased by $9.6 million to $45.3 million, compared to $35.7 million for the three months ended June 30, 2012, due to an increase in home heating oil and propane volume ($7.0 million), the impact of higher home heating oil and propane margins ($2.5 million) and the additional gross profit from other petroleum products ($0.1 million).

Cost of Installations and Service

For the three months ended June 30, 2013, cost of installation and service increased by $4.2 million, or 10.6%, to $44.1 million, compared to $39.9 million for the three months ended June 30, 2012, due to the additional service costs associated with colder temperatures and the increase in service and installation revenues.

Installation costs for the three months ended June 30, 2013, increased by $1.5 million, or 10.3%, to $15.7 million, compared to $14.3 million in installation costs for the three months ended June 30, 2012. Installation costs as a percentage of installation sales for the three months ended June 30, 2013, and the three months ended June 30, 2012, were 84.6% and 84.0%, respectively. Service expenses increased to $28.4 million for the three months ended June 30, 2013, or 80.9%, of service sales, versus $25.6 million, or 76.0% of service sales, for the three months ended March 31, 2012. We achieved a combined profit from service and installation of $9.6 million for the three months ended June 30, 2013, compared to a combined profit of $10.8 million for the three months ended June 30, 2012. 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 June 30, 2013, the change in the fair value of derivative instruments resulted in a $1.9 million charge due to the expiration of certain hedged positions (a $1.5 million credit) and a decrease in the market value for unexpired hedges (a $3.4 million charge).

During the three months ended June 30, 2012, the change in the fair value of derivative instruments resulted in a $11.2 million charge due to the expiration of certain hedged positions (a $0.7 million charge) and an decrease in market value for unexpired hedges (a $10.5 million charge).

Delivery and Branch Expenses

For the three months ended June 30, 2013, delivery and branch expense increased $7.0 million, or 15.1%, to $53.8 million, compared to $46.8 million for the three months ended June 30, 2012, due to the 21.7% increase in home heating oil and propane volume.

Depreciation and Amortization

For the three months ended June 30, 2013, depreciation and amortization expenses decreased slightly by $0.3 million, or 6.1%, to $4.3 million, compared to $4.6 million for the three months ended June 30, 2012.

General and Administrative Expenses

For the three months ended June 30, 2013, general and administrative expenses increased $0.6 million, to $4.6 million, from $4.0 million for the three months ended June 30, 2012, largely due to an increase in profit sharing expense. The Partnership accrues approximately 6.0% of Adjusted EBITDA as defined in the profit sharing plan for distribution to its employees, and this amount is payable when the Partnership achieves Adjusted EBITDA of at least 70% of the amount budgeted. The dollar amount of the profit sharing pool is subject to increases and decreases in line with increases and decreases in Adjusted EBITDA.

Interest Expense

For the three months ended June 30, 2013, interest expense increased $0.1 million, or 3.3%, to $3.5 million compared to $3.4 million for the three months ended June 30, 2012, largely due to an increase in average working capital borrowings of $12.9 million.

Interest Income

For the three months ended June 30, 2013, interest income increased $0.2 million to $1.7 million, compared to $1.5 million for the three months ended June 30, 2012, due to higher finance charges.

Amortization of Debt Issuance Costs

For the three months ended June 30, 2013, amortization of debt issuance costs decreased slightly by $0.1 million to $0.4 million.

Income Tax Expense / Benefit

For the three months ended June 30, 2013, income tax benefit decreased by $6.2 million to $4.4 million from $10.6 million for the three months ended June 30, 2012, due to a decrease in loss before income taxes of $10.5 million as well as a decline in the Partnership’s effective income tax rate from 47.5% for the three months ended June 30, 2012, to 36.5% for the three months ended June 30, 2013. This rate decrease was primarily due to the non-recurrence of a recording of a previously unrecognized tax benefit in the three months ended June 30, 2012.

Net Income / Loss

For the three months ended June 30, 2013, the net loss decreased $4.2 million to $7.6 million, from $11.8 million for the three months ended June 30, 2012, as the decrease in the pretax loss of $10.5 million was reduced by a decline in the income tax benefit of $6.2 million.

Adjusted EBITDA

For the three months ended June 30, 2013, the Adjusted EBITDA loss decreased by $0.8 million, or 18.3%, to $3.4 million as the impact of 27.2% colder temperatures and higher home heating oil and propane per gallon margins more than offset the impact of net customer attrition.

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 June 30,
(in thousands)	2013			2012

Net loss	$	(7,588	)	$	(11,789	)
Plus:
Income tax benefit		(4,364	)		(10,645	)
Amortization of debt issuance cost		415			486
Interest expense, net		1,851			1,897
Depreciation and amortization		4,328			4,608

EBITDA (a)		(5,358	)		(15,443	)

(Increase) / decrease in the fair value of derivative instruments		1,910			11,225

Adjusted EBITDA (a)		(3,448	)		(4,218	)

Add / (subtract)
Income tax expense		4,364			10,645
Interest expense, net		(1,851	)		(1,897	)
Provision for losses on accounts receivable		1,611			615
Decrease in accounts receivables		136,636			89,323
(Increase) decrease in inventories		(7,334	)		8,952
Increase in customer credit balances		9,670			20,605
Change in deferred taxes		(4,359	)		(9,273	)
Decrease in weather hedge contract receivable		—			12,500
Change in other operating assets and liabilities		(25,550	)		(10,393	)

Net cash provided by operating activities	$	109,739		$	116,859



Net cash used in investing activities	$	(1,551	)	$	(12,971	)



Net cash used in financing activities	$	(74,374	)	$	(37,709	)

(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.

Nine Months Ended June 30, 2013

Compared to the Nine Months Ended June 30, 2012

Volume

For the nine months ended June 30, 2013, retail volume of home heating oil and propane increased by 47.5 million gallons, or 18.5%, to 304.2 million gallons, compared to 256.7 million gallons for the nine months ended June 30, 2012. For those locations where the Partnership had existing operations during both periods, which we sometimes refer to as the “base business” (i.e., excluding acquisitions), temperatures (measured on a heating degree day basis) for the nine months ended June 30, 2013, were 22.3% colder than the nine months ended June 30, 2012, but 4.1% warmer than normal, as reported by the National Oceanic and Atmospheric Administration (“NOAA”). For the twelve months ended June 30, 2013, net customer attrition for the base business was 3.7%. 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 product. The impact of 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 included in the chart below under the heading “Other.” In addition, October 29, 2012, storm Sandy made landfall in our service area, resulting in widespread power outages that affected a number of our customers. 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 storm Sandy. The home heating oil and propane volume loss due to storm Sandy is also 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 as follows:


(in millions of gallons)	Heating Oil and Propane
Volume - Nine months ended June 30, 2012		256.7
Acquisitions		13.3
Impact of colder temperatures		54.3
Net customer attrition		(9.3	)
Other		(10.8	)

Change		47.5


Volume - Nine months ended June 30, 2013		304.2

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 nine months ended June 30, 2013, compared to the nine months ended June 30, 2012:


	Nine Months Ended
Customers	June 30, 2013			June 30, 2012
Residential Variable		41.8	%		42.7	%
Residential Price-Protected		44.3	%		44.2	%
Commercial/Industrial/Other		13.9	%		13.1	%

Total		100.0	%		100.0	%

Volume of other petroleum products increased by 5.8 million gallons, or 14.4%, to 46.0 million gallons for the nine months ended June 30, 2013, compared to 40.2 million gallons for the nine months ended June 30, 2012, largely due to an increase in motor fuel demand as a result of storm Sandy (including to power generators) and higher home heating oil wholesale sales.

Product Sales

For the nine months ended June 30, 2013, product sales increased $0.2 billion, or 19.1%, to $1.4 billion, compared to $1.2 billion for the nine months ended June 30, 2012, primarily due to an increase in total volume of 18.0%.

Installation and Service Sales

For the nine months ended June 30, 2013, installation and service sales increased $17.0 million, or 11.3%, to $167.9 million, compared to $150.9 million for the nine months ended June 30, 2012, due to additional revenue from acquisitions of $5.4 million and an increase in the base business of $11.6 million largely attributable to storm Sandy-related service and installation billings and the additional service costs associated with 22.2% colder temperatures.

Cost of Product

For the nine months ended June 30, 2013, cost of product increased $170.0 million, or 18.4%, to $1,091.9 million, compared to $921.9 million for the nine months ended June 30, 2012, largely due to an increase in total volume of 18.0%.

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 nine months ended June 30, 2013, increased by $0.0193 per gallon, or 2.1%, to $0.9567 per gallon, from $0.9374 per gallon during the nine months ended June 30, 2012. Product sales and cost of product include home heating oil, propane, other petroleum products and liquidated damages billings.


	Nine Months Ended
	June 30, 2013				June 30, 2012
Home Heating Oil and Propane	Amount (in millions)		Per Gallon		Amount (in millions)		Per Gallon
Volume		304.2				256.7

Sales	$	1,237.6	$	4.0683	$	1,037.0	$	4.0399
Cost	$	946.6	$	3.1116	$	796.4	$	3.1025


Gross Profit	$	291.0	$	0.9567	$	240.6	$	0.9374


Other Petroleum Products	Amount (in millions)		Per Gallon		Amount (in millions)		Per Gallon
Volume		46.0				40.2

Sales	$	158.7	$	3.4521	$	135.6	$	3.3756
Cost	$	145.4	$	3.1624	$	125.6	$	3.1246


Gross Profit	$	13.3	$	0.2897	$	10.1	$	0.2509


Total Product	Amount (in millions)				Amount (in millions)
Sales	$	1,396.3			$	1,172.6
Cost	$	1,091.9			$	921.9


Gross Profit	$	304.4			$	250.7

For the nine months ended June 30, 2013, total product gross profit increased by $53.7 million to $304.4 million, compared to $250.7 million for the nine months ended June 30, 2012, due to an increase in home heating oil and propane volume ($44.6 million), the impact of higher home heating oil and propane margins ($5.9 million) and the additional gross profit from other petroleum products ($3.2 million).

Cost of Installations and Service

For the nine months ended June 30, 2013, cost of installation and service increased by $16.1 million, or 11.7%, to $152.7 million, compared to $136.6 million for the nine months ended June 30, 2012, due to a $4.5 million increase related to acquisitions and an $11.6 million increase tied to our base business largely due to Sandy and the additional service costs associated with 22.2% colder temperatures.

Installation costs for the nine months ended June 30, 2013, increased by $8.8 million, or 19.5%, to $54.1 million, compared to $45.3 million in installation costs for the nine months ended June 30, 2012. Installation costs as a percentage of installation sales for the nine months ended June 30, 2013, and the nine months ended June 30, 2012, were 84.2% and 84.8%, respectively. Service expenses increased to $98.5 million for the nine months ended June 30, 2013, or 95.1%, of service sales, versus $91.3 million, or 93.7% of service sales, for the nine months ended June 30, 2012. We achieved a combined profit from service and installation of $15.2 million for the nine months ended June 30, 2013, compared to a combined profit of $14.3 million for the nine months ended June 30, 2012. This improvement of $0.9 million was largely due to acquisitions and service and installation work following storm Sandy. 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 nine months ended June 30, 2013, the change in the fair value of derivative instruments resulted in a $6.4 million charge due to the expiration of certain hedged positions (a $1.0 million charge) and a decrease in the market value for unexpired hedges (a $5.4 million charge).

During the nine months ended June 30, 2012, the change in the fair value of derivative instruments resulted in a $1.4 million charge due to the expiration of certain hedged positions (a $7.0 million credit) a decrease in market value for unexpired (an $8.4 million charge).

Delivery and Branch Expenses

For the nine months ended June 30, 2013, delivery and branch expense increased $29.3 million, or 16.6%, to $205.5 million, compared to $176.2 million for the nine months ended June 30, 2012, due to higher delivery and branch expenses of $10.2 million from the additional volume sold in the base business, the additional expense from acquisitions of $6.9 million and the absence of a weather hedge benefit of $12.5 million. During the nine months ended June 30, 2012, the Partnership recorded a benefit of $12.5 million under its warm weather hedge which reduced delivery and branch expenses with no similar benefit recorded in the nine months ended June 30, 2013. Bad debt expense also rose by $1.0 million due to the increase in sales of $240.6 million.

On a cents per gallon basis (excluding the credit recorded under the Partnership’s weather hedge contract recorded during the nine months ended June 30, 2012), delivery and branch expenses for the nine months ended June 30, 2013, decreased $0.0445, or 6.8%, to $0.6064, compared to $0.6509 for the nine months ended June 30, 2012, as certain fixed operating expenses were spread over a larger volume base in the nine months ended June 30, 2013, versus the nine months ended June 30, 2012.

Depreciation and Amortization

For the nine months ended June 30, 2013, depreciation and amortization expenses increased by $0.9 million, or 7.8%, to $13.0 million, compared to $12.1 million for the nine months ended June 30, 2012.

Depreciation expense was higher by $0.1 million due to an increase of $0.9 million from fiscal 2012 and fiscal 2013 acquisitions which was partially offset by a decrease of $0.5 million related to fleet and equipment assets which became fully depreciated in fiscal 2012 and fiscal 2013. Amortization expense increased by $0.8 million, due to fiscal 2012 and fiscal 2013 customer lists acquired with seven and ten year lives and trade names acquired with twenty year lives.

General and Administrative Expenses

For the nine months ended June 30, 2013, general and administrative expenses decreased $0.1 million, or 0.9%, to $13.8 million, from $13.9 million for the nine months ended June 30, 2012, as lower legal and professional, acquisition and other expenses of $1.8 million were offset by an increase in profit sharing expense of $1.7 million.

The Partnership accrues approximately 6.0% of Adjusted EBITDA as defined in the profit sharing plan for distribution to its employees, and this amount is payable when the Partnership achieves Adjusted EBITDA of at least 70% of the amount budgeted. The dollar amount of the profit sharing pool is subject to increases and decreases in line with increases and decreases in Adjusted EBITDA.

Interest Expense

For the nine months ended June 30, 2013, interest expense increased $0.3 million, or 2.6%, to $11.0 million compared to the $10.7 million for the nine months ended June 30, 2012 largely due to an increase in average working capital borrowings of $7.9 million.

Interest Income

For the nine months ended June 30, 2013, interest income increased $1.5 million to $5.0 million, compared to $3.5 million for the nine months ended June 30, 2012, due to higher finance charge income.

Amortization of Debt Issuance Costs

For the nine months ended June 30, 2013, amortization of debt issuance costs increased by $0.2 million to $1.3 million, compared to $1.1 million for the nine months ended June 30, 2012, due considerably to the commencement of amortization of the April 2012 revolving credit facility agreement amendment fees.

Income Tax Expense

For the nine months ended June 30, 2013, income tax expense increased by $8.3 million to $29.7 million from $21.4 million for the nine months ended June 30, 2012, due to the increase in pretax income of $20.5 million. The effective income tax rate was unchanged at 40.4%.

Net Income

For the nine months ended June 30, 2013, net income increased $12.2 million to $43.8 million, from $31.6 million for the nine months ended June 30, 2012, as the increase in pretax income of $20.5 million was greater than the increase in income tax expense of $8.3 million.

Adjusted EBITDA

For the nine months ended June 30, 2013, Adjusted EBITDA increased by $25.5 million, or 34.0 %, to $100.3 million as the impact of 22.3% colder temperatures, higher home heating oil and propane per gallon margins, acquisitions, and the favorable impact of storm Sandy on motor fuel sales and service and installation revenue more than offset the volume decline in the base business attributable to net customer attrition and other factors. Adjusted EBITDA for the nine months ended June 30, 2012, included a $12.5 million benefit that the Partnership recorded under its weather hedge contract due to the abnormally warm weather in that period, with no similar benefit recorded during the nine months ended June 30, 2013.

EBITDA and Adjusted EBITDA are calculated as follows:


	Nine Months Ended June 30,
(in thousands)	2013			2012

Net income	$	43,843		$	31,624
Plus:
Income tax expense		29,670			21,398
Amortization of debt issuance cost		1,325			1,145
Interest expense, net		6,020			7,242
Depreciation and amortization		13,007			12,066

EBITDA (a)		93,865			73,475

(Increase) / decrease in the fair value of derivative instruments		6,428			1,362

Adjusted EBITDA (a)		100,293			74,837

Add / (subtract)
Income tax expense		(29,670	)		(21,398	)
Interest expense, net		(6,020	)		(7,242	)
Provision for losses on accounts receivable		7,814			6,864
Increase in accounts receivables		(71,929	)		(21,831	)
(Increase) decrease in inventories		(1,585	)		45,067
Decrease in customer credit balances		(52,719	)		(15,697	)
Change in deferred taxes		4,292			13,657
Change in other operating assets and liabilities		17,894			6,842

Net cash provided by (used in) operating activities	$	(31,630	)	$	81,099



Net cash used in investing activities	$	(3,644	)	$	(41,515	)



Net cash used in financing activities	$	(28,435	)	$	(35,141	)

(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 nine months ended June 30, 2013, cash used in operating activities was $31.6 million or $112.7 million greater than the $81.1 million of cash provided by operating activities for the nine months ended June 30, 2012. While cash generated from operations increased by $10.0 million largely due to the impact of 22.2% colder weather, cash used to finance accounts receivable, including customers on our budget payment plans, increased by $87.1 million. As of June 30, 2013, days sales outstanding were 56.1 days compared to 48.4 days as of June 30, 2012 and 60.1 days as of June 30, 2011. The increase in days sales outstanding as of June 30, 2013 when compared to June 30, 2012 was largely due to the increase in sales volume resulting from colder temperatures. In addition, at the beginning of fiscal 2012 the Partnership had purchased approximately 11.5 million gallons more liquid product for the upcoming heating season than at the beginning of fiscal 2013 and as of June 30, 2013 had purchased 3.7 million gallons more than as of June 30, 2012. As a result, cash used in operations for the purchase of inventory was $46.7 million greater in the nine months ended June 30, 2013, than in the nine months ended June 30, 2012. The timing of certain accruals and payments, including income taxes, insurance and amounts due under the Partnership’s profit sharing plan, provided $11.1 million of cash for the nine months ended June 30, 2013, compared to the nine months ended June 30, 2012.

Investing Activities

Our capital expenditures for the nine months ended June 30, 2013, totaled $3.1 million, as we invested in computer hardware and software ($0.7 million), refurbished certain physical plants ($0.5 million), expanded our propane operations ($1.4 million) and made additions to our fleet and other equipment ($0.5 million). We also completed one acquisition for $0.6 million.

Our capital expenditures for the nine months ended June 30, 2012, totaled $3.5 million, as we invested in computer hardware and software ($0.7 million), refurbished certain physical plants ($0.5 million), expanded our propane operations ($1.0 million) and made additions to our fleet and other equipment ($1.3 million). We also completed five acquisitions for $38.3 million and allocated $31.2 million of the gross purchase price to intangible assets (including $3.0 million to goodwill), $7.5 million to fixed assets, and $0.4 million to working capital.

Financing Activities

During the nine months ended June 30, 2013, we borrowed $111.5 million under our credit facility and subsequently repaid $111.5 million. We also paid distributions of $14.3 million to our common unit holders, $0.2 million to our General Partner (including $0.1 million of incentive distributions as provided in our Partnership Agreement) and repurchased 3.0 million units for $13.9 million in connection with the unit repurchase plan.

During the nine months ended June 30, 2012, we borrowed $86.2 million under our revolving credit facility and repaid $86.2 million. We also paid distributions of $14.6 million to our common unit holders, $0.2 million to our General Partner (including $0.1 million of incentive distributions as provided in our Partnership Agreement) and repurchased 3.9 million units for $19.6 million in connection with our unit repurchase plan.

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 June 30, 2013, ($44.4 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, including under our $250 million shelf registration statement.

Our asset-based revolving credit facility, which expires in June 2016, provides us with the ability to borrow up to $250 million ($350 million during the heating season from November through April of each year) for working capital purposes (subject to certain borrowing base limitations and coverage ratios), including the issuance of up to $100 million in letters of credit. We can increase the facility size by $100 million without the consent of the bank group. However, the bank group is not obligated to fund the $100 million increase. If the bank group elects not to fund the increase, we can add additional lenders to the group with the consent of the Agent which shall not be unreasonably withheld. Obligations under the revolving credit facility are guaranteed by us and our subsidiaries and secured by liens on substantially all of our assets, including accounts receivable, inventory, general intangibles, real property, fixtures and equipment. As of June 30, 2013, there were $45.0 million in letters of credit outstanding, of which $44.7 million are for current and future insurance reserves and bonds and $0.3 million are for seasonal inventory purchases and other working capital purposes.

Under the terms of the revolving credit facility, we must maintain at all times either Availability (borrowing base less amounts borrowed and letters of credit issued) of 12.5% of the facility size or a fixed charge coverage ratio of not less than 1.10, which is calculated based upon Adjusted EBITDA for the trailing twelve month period. As of June 30, 2013, Availability, as defined in the revolving credit facility agreement, was $139.1 million, which exceeded the minimum required, and the fixed charge coverage ratio for the twelve months ended June 30, 2013, was in excess of 1.10.

Maintenance capital expenditures for the remainder of 2013 are estimated to be approximately $1.4 to $2.1 million, excluding the capital requirements for leased fleet. In addition, we plan to invest an estimated $0.3 million in our propane operations. We anticipate paying distributions during the remainder of 2013 at the current quarterly level of $0.0825 per unit for an aggregate of approximately $4.8 million to common unit holders, $70 thousand to our General Partner (including $50 thousand of incentive distribution as provided in our Partnership Agreement) and $50 thousand 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. Based upon certain actuarial assumptions, we estimate that the Partnership will make cash contributions to its frozen defined benefit pension obligations totaling approximately $1.2 million for the remainder of fiscal 2013. We continue to seek attractive acquisition opportunities within the Availability constraints of our revolving credit facility and our other potential funding resources.

On July 19, 2012, the Board of Directors authorized the repurchase of up to 3.0 million of the Partnership’s common units, which we refer to as Plan III. Through the date of this Report the Partnership repurchased 1.9 million units at a cost of $8.3 million and intends to continue to repurchase units under this Plan. The Board authorized the purchase of an additional 1.15 million common units on June 28, 2013 that are not part of Plan III. On July 22, 2013, the Board of Directors increased the number of units that can be repurchased under Plan III by 1.9 million units which restored the remaining number of units that can be repurchased under Plan III to 3.0 million.

Partnership Distribution Provisions

On July 22, 2013, we declared a quarterly distribution of $0.0825 per unit, or $0.33 per unit on an annualized basis, on all common units with respect to the third quarter of fiscal 2013, payable on August 13, 2013, to holders of record on August 5, 2013. In accordance with our Partnership Agreement, the amount of distributions in excess of the minimum quarterly distribution of $0.0675, are distributed 90% to the holders of common units and 10% to the holders of the General Partner units (until certain distribution levels are met), subject to the management incentive compensation plan. As a result, $4.8 million will be paid to the common unit holders, $70 thousand to the General Partner (including $50 thousand of incentive distribution as provided in our Partnership Agreement) and $50 thousand to management pursuant to the management incentive compensation plan which provides for certain members of management to receive incentive distributions that would otherwise be payable to the General Partner.

Contractual Obligations and Off-Balance Sheet Arrangements

There has been no material change to Contractual Obligations and Off-Balance Sheet Arrangements since our September 30, 2012, Form 10-K disclosure and therefore, the table has not been included in this Form 10-Q.

Recent Accounting Pronouncements

The following new accounting standard is currently being evaluated by the Partnership, and is more fully described in Note 2. Summary of Significant Accounting Policies - Recent Accounting Pronouncements, of the consolidated financial statements:

•

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

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

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

At June 30, 2013, we had outstanding borrowings totaling $124.4 million, none of which is subject to variable interest rates.

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 June 30, 2013, the fair market value of these outstanding derivatives would increase by $6.7 million to a value of $2.6 million; and conversely a hypothetical ten percent decrease in the cost of product would decrease the fair market value of these outstanding derivatives by $3.1 million to a negative value of $(7.2) 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 June 30, 2013. Based on that evaluation, such principal executive officer and principal financial officer concluded that the Partnership’s disclosure controls and procedures were effective as of June 30, 2013 at the reasonable level of assurance. For purposes of Rule 13a-15(e), the term disclosure controls and procedures means controls and other procedures of an issuer that are designed to ensure that information required to be disclosed by the issuer in the reports that it files or submits under the Act (15 U.S.C. 78a et seq.) is recorded, processed, summarized and reported, within the time periods specified in the Commission’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Act is accumulated and communicated to the issuer’s management, including its principal executive and principal financial officer, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

b) Change in Internal Control over Financial Reporting.

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

c) The General Partner and the Partnership believe that a controls system, no matter how well designed and operated, cannot provide absolute assurance that the objectives of the controls system are met, and no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within a Partnership have been detected. Therefore, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Our disclosure controls and procedures are designed to provide such reasonable assurances of achieving our desired control objectives, and the principal executive officer and principal financial officer of our general partner have concluded, as of June 30, 2013, that our disclosure controls and procedures were effective in achieving that level of reasonable assurance.

PART II OTHER INFORMATION

Item 1

Legal Proceedings

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

Item 1A

Risk Factors

In addition to the other information set forth in this Report, investors should carefully review and consider the information regarding certain factors which could materially affect our business, results of operations, financial condition and cash flows set forth below and in Part I Item 1A. “Risk Factors” in our Fiscal 2012 Form 10-K. We may disclose changes to such factors or disclose additional factors from time to time in our future filings with the SEC.

Item 2

Unregistered Sales of Equity Securities and Use of Proceeds

See Note 3. to the Consolidated Financial Statements for information concerning the Partnership’s repurchase of common units in the nine months ended June 30, 2013.

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 June 30, 2013 formatted in Extensible Business Reporting Language (XBRL): (i) the Condensed Consolidated Balance Sheets, (ii) the Condensed Consolidated Statements of Operations, (iii) the Condensed Consolidated Statements of Comprehensive Income, (iv) the Condensed Consolidated Statements of Partners’ Capital, (v) the Condensed Consolidated Statements of Cash Flows and (vi) related notes.

#101.INS		XBRL Instance Document.

#101.SCH		XBRL Taxonomy Extension Schema Document.

#101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document.

#101.LAB		XBRL Taxonomy Extension Label Linkbase Document.

#101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document.

#101.DEF		XBRL Taxonomy Extension Definition Linkbase Document.

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

SIGNATURE

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

Star Gas Partners, L.P.

(Registrant)

By: Kestrel Heat LLC AS GENERAL PARTNER


Signature	Title	Date

/S/ RICHARD F. AMBURY Richard F. Ambury	Executive Vice President, Chief Financial Officer, Treasurer and Secretary Kestrel Heat LLC (Principal Financial Officer)	August 7, 2013

Signature	Title	Date

/S/ RICHARD G. OAKLEY Richard G. Oakley	Vice President - Controller Kestrel Heat LLC (Principal Accounting Officer)	August 7, 2013