FORM 10-Q

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

10-Q 1 d932607d10q.htm FORM 10-Q 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, 2015

¨	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.)

9 West Broad 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, 2015, the registrant had 57,282,352 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, 2015 (unaudited) and September 30, 2014		3
Condensed Consolidated Statements of Operations (unaudited) for the three and nine months ended June 30, 2015 and June 30, 2014		4
Condensed Consolidated Statements of Comprehensive Income (unaudited) for the three and nine months ended June 30, 2015 and June 30, 2014		5
Condensed Consolidated Statement of Partners’ Capital (unaudited) for the nine months ended June 30, 2015		6
Condensed Consolidated Statements of Cash Flows (unaudited) for the nine months ended June 30, 2015 and June 30, 2014		7
Notes to Condensed Consolidated Financial Statements (unaudited)		8-17
Item 2 - Management’s Discussion and Analysis of Financial Condition and Results of Operations		18-39
Item 3 - Quantitative and Qualitative Disclosures About Market Risk		40
Item 4 - Controls and Procedures		40-41

Part II Other Information:
Item 1 - Legal Proceedings		41
Item 1A - Risk Factors		41-42
Item 2 - Unregistered Sales of Equity Securities and Use of Proceeds		42
Item 6 - Exhibits		43
Signatures		44

Part I. FINANCIAL INFORMATION

Item 1. Condensed Consolidated Financial Statements

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS


(in thousands)	June 30, 2015			September 30, 2014
	(unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	122,648		$	48,999
Receivables, net of allowance of $9,582 and $9,220, respectively		135,915			123,800
Inventories		46,597			59,240
Fair asset value of derivative instruments		224			2,342
Current deferred tax assets, net		38,169			38,141
Prepaid expenses and other current assets		23,515			23,943

Total current assets		367,068			296,465

Property and equipment, net		64,226			67,419
Goodwill		209,404			209,331
Intangibles, net		92,079			100,783
Deferred charges and other assets, net		11,086			11,109

Total assets	$	743,863		$	685,107

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Accounts payable	$	14,352		$	21,644
Fair liability value of derivative instruments		2,378			12,358
Current maturities of long-term debt		25,000			—
Accrued expenses and other current liabilities		128,353			102,934
Unearned service contract revenue		44,834			43,901
Customer credit balances		46,048			72,595

Total current liabilities		260,965			253,432

Long-term debt		99,663			124,572
Long-term deferred tax liabilities, net		34,496			25,181
Other long-term liabilities		8,069			8,677

Partners’ capital
Common unitholders		363,224			296,968
General partner		83			(105	)
Accumulated other comprehensive loss, net of taxes		(22,637	)		(23,618	)

Total partners’ capital		340,670			273,245

Total liabilities and partners’ capital	$	743,863		$	685,107

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)	2015			2014			2015			2014
Sales:
Product	$	184,891		$	267,694		$	1,325,907		$	1,571,034
Installations and services		60,713			58,817			181,223			168,328

Total sales		245,604			326,511			1,507,130			1,739,362
Cost and expenses:
Cost of product		133,053			215,826			905,117			1,213,967
Cost of installations and services		52,786			50,003			173,831			156,478
(Increase) decrease in the fair value of derivative instruments		(5,415	)		(3,308	)		(9,756	)		(4,661	)
Delivery and branch expenses		64,575			66,347			249,516			227,175
Depreciation and amortization expenses		6,204			5,760			18,579			15,036
General and administrative expenses		6,173			5,140			19,090			16,995
Finance charge income		(1,699	)		(2,460	)		(4,042	)		(5,671	)

Operating income (loss)		(10,073	)		(10,797	)		154,795			120,043
Interest expense, net		(3,491	)		(5,427	)		(10,767	)		(13,324	)
Amortization of debt issuance costs		(406	)		(394	)		(1,209	)		(1,205	)

Income (loss) before income taxes		(13,970	)		(16,618	)		142,819			105,514
Income tax expense (benefit)		(5,611	)		(7,026	)		59,937			43,602

Net income (loss)	$	(8,359	)	$	(9,592	)	$	82,882		$	61,912
General Partner’s interest in net income (loss)		(47	)		(54	)		469			349

Limited Partners’ interest in net income (loss)	$	(8,312	)	$	(9,538	)	$	82,413		$	61,563

Basic and diluted income (loss) per Limited Partner Unit (1):	$	(0.15	)	$	(0.17	)	$	1.21		$	0.91

Weighted average number of Limited Partner units outstanding:
Basic and Diluted		57,282			57,468			57,286			57,482

(1)	See Note 13 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)	2015			2014			2015			2014
Net income (loss)	$	(8,359	)	$	(9,592	)	$	82,882		$	61,912
Other comprehensive income:
Unrealized gain on pension plan obligation (1)		556			528			1,670			1,584
Tax effect of unrealized gain on pension plan		(230	)		(217	)		(689	)		(649	)

Total other comprehensive income		326			311			981			935

Total comprehensive income (loss)	$	(8,033	)	$	(9,281	)	$	83,863		$	62,847

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

See accompanying notes to condensed consolidated financial statements.

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL


	Number of Units
(in thousands—unaudited)	Common			General Partner		Common			General Partner			Accum. Other Comprehensive Income (Loss)			Total Partners’ Capital
Balance as of September 30, 2014		57,405			326	$	296,968		$	(105	)	$	(23,618	)	$	273,245
Net income		—			—		82,413			469			—			82,882
Unrealized gain on pension plan obligation		—			—		—			—			1,670			1,670
Tax effect of unrealized gain on pension plan		—			—		—			—			(689	)		(689	)
Distributions		—			—		(15,466	)		(281	)		—			(15,747	)
Retirement of units (1)		(123	)		—		(691	)		—			—			(691	)

Balance as of June 30, 2015 (unaudited)		57,282			326	$	363,224		$	83		$	(22,637	)	$	340,670

(1)	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)	2015			2014
Cash flows provided by (used in) operating activities:
Net income	$	82,882		$	61,912

Adjustment to reconcile net income to net cash provided by (used in) operating activities:
(Increase) decrease in fair value of derivative instruments		(9,756	)		(4,661	)
Depreciation and amortization		19,788			16,241
Provision for losses on accounts receivable		5,062			8,862
Change in deferred taxes		8,598			9,051
Changes in operating assets and liabilities:
Increase in receivables		(17,730	)		(78,276	)
Decrease in inventories		12,691			24,706
Decrease in other assets		1,759			3,955
Decrease in accounts payable		(6,984	)		(7,132	)
Decrease in customer credit balances		(26,595	)		(43,588	)
Increase in other current and long-term liabilities		26,456			14,183

Net cash provided by operating activities		96,171			5,253

Cash flows provided by (used in) investing activities:
Capital expenditures		(5,227	)		(6,510	)
Proceeds from sales of fixed assets		212			139
Acquisitions (net of cash acquired of $0, and $4,151 respectively)		(1,069	)		(97,950	)

Net cash used in investing activities		(6,084	)		(104,321	)

Cash flows provided by (used in) financing activities:
Revolving credit facility borrowings		12,296			195,482
Revolving credit facility repayments		(12,296	)		(155,938	)
Distributions		(15,747	)		(14,737	)
Unit repurchases		(691	)		(1,300	)
Deferred charges		—			(2,381	)

Net cash provided by (used in) financing activities		(16,438	)		21,126

Net increase (decrease) in cash and cash equivalents		73,649			(77,942	)

Cash and cash equivalents at beginning of period		48,999			85,057

Cash and cash equivalents at end of period	$	122,648		$	7,115

See accompanying notes to condensed consolidated financial statements.

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

1) Partnership Organization

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

The Partnership is organized as follows:

•

The Partnership is a master limited partnership, which at June 30, 2015, had outstanding 57.3 million Common Units (NYSE: “SGU”), representing 99.43% limited partner interest in Star Gas Partners, and 0.3 million general partner units, representing 0.57% general partner interest in Star Gas Partners. The general partner of the Partnership is Kestrel Heat, LLC, a Delaware limited liability company (“Kestrel Heat” or the “general partner”). The Board of Directors of Kestrel Heat (the “Board”) is appointed by its sole member, Kestrel Energy Partners, LLC, a Delaware limited liability company (“Kestrel”).

•

The Partnership owns 100% of Star Acquisitions, Inc. (“SA”), a Minnesota corporation that owns 100% of Petro Holdings, Inc. (“Petro”). SA and its subsidiaries are subject to Federal and state corporate income taxes. The Partnership’s operations are conducted through Petro and its subsidiaries. Petro is primarily a Northeast and Mid-Atlantic region retail distributor of home heating oil and propane that at June 30, 2015, served approximately 446,000 full-service residential and commercial home heating oil and propane customers. Petro also sold diesel fuel, gasoline and home heating oil to approximately 75,000 customers on a delivery only basis. In addition, Petro installed, maintained, and repaired heating and air conditioning equipment for its customers and provided ancillary home services, including home security and plumbing, to approximately 24,000 customers.

•

Star Gas Finance Company (“SGFC”) is a 100% owned subsidiary of the Partnership. SGFC serves as the co-issuer, jointly and severally with the Partnership, of its $125 million principal amount of 8.875% Senior Notes outstanding at June 30, 2015, due December 2017. SGFC and the Partnership are dependent on distributions, including inter-company interest payments from its subsidiaries, to service the debt issued by SGFC and the Partnership. The distributions from these subsidiaries are not guaranteed and are subject to certain loan restrictions. SGFC has nominal assets and conducts no business operations.

In July 2015, the Partnership and SGFC delivered to the trustee of the indenture governing the 8.875% Senior Notes a notice of redemption to redeem all of the outstanding $125 million in face amount of these notes at a redemption price of 104.438% plus any accrued but unpaid interest through the redemption date. (See Note 9—Long-Term Debt and Bank Facility Borrowings and Note 14. Subsequent Events)

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, 2015, and June 30, 2014, 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, 2014.

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 May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers, which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. This ASU will replace most existing revenue recognition guidance in GAAP when it becomes effective. This new guidance is effective for our annual reporting period beginning in the first quarter of fiscal 2019, with early adoption permitted beginning in the first quarter of fiscal 2018. The standard permits the use of either the retrospective or cumulative effect transition method. The Partnership is evaluating the effect that ASU 2014-09 will have on its consolidated financial statements and related disclosures. The Partnership has not yet selected a transition method nor has it determined the timing of adoption.

In April 2015, the FASB issued ASU No. 2015-03, Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. The update requires debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability instead of being presented as an asset. The update requires retrospective application and represents a change in accounting principle. The update is effective for our annual reporting period beginning in the first quarter of fiscal 2017, with early adoption permitted. The Partnership expects the impact of ASU 2015-03 will be limited to the presentation of debt issuance cost on its balance sheet.

3) Common Unit Repurchase and Retirement

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

Under the Partnership’s second amended and restated revolving credit facility agreement dated January 14, 2014 (and also under the third amended and restated revolving credit facility agreement entered into on July 30, 2015), in order to repurchase Common Units we must maintain Availability (as defined in the respective amended and restated revolving credit facility agreements) of $45 million, 15.0% of the facility size of $300 million (assuming the non-seasonal aggregate commitment is outstanding) on a historical pro forma and forward-looking basis, and a fixed charge coverage ratio of not less than 1.15 measured as of the date of repurchase. The Partnership was in compliance with this covenant for all unit repurchases made during the nine months ended June 30, 2015.

The following table shows repurchases under Plan III.


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

						6,044

Plan III—Fiscal years 2012 to 2014 total ( c)		3,619	$	4.69		2,425

Plan III—First quarter fiscal year 2015 total		123	$	5.64		2,302
Plan III—Second quarter fiscal year 2015 total		—	$	—		2,302
Plan III—Third quarter fiscal year 2015 total		—	$	—		2,302

Plan III—Nine months fiscal year 2015 total		123	$	5.64		2,302

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

(b)	Amounts include repurchase costs.

(c)	Includes 1.45 million common units acquired in a private transaction.

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

The Partnership uses derivative instruments such as futures, options and swap agreements in order to mitigate exposure to market risk associated with the purchase of home heating oil for price-protected customers, physical inventory on hand, inventory in transit, priced purchase commitments and internal fuel usage. The Partnership has elected not to designate its derivative instruments as hedging derivatives, but rather as economic hedges whose change in fair value is recognized in its statement of operations in the line item (Increase) decrease in the fair value of derivative instruments. Depending on the risk being economically hedged, realized gains and losses are recorded in cost of product, cost of installations and services, or delivery and branch expenses.

As of June 30, 2015, to hedge a substantial majority of the purchase price associated with heating oil gallons anticipated to be sold to its price-protected customers, the Partnership held the following derivative instruments that settle in future months to match anticipated sales: 5.2 million gallons of swap contracts, 4.4 million gallons of call options, 2.7 million gallons of put options and 60.2 million net gallons of synthetic call options. 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, 2015, had 7.0 million gallons of purchased future contracts and 21.8 million gallons of sold future contracts that settle in future months. To hedge its internal fuel usage for the remainder of fiscal 2015 and for fiscal 2016, the Partnership, as of June 30, 2015, had 3.0 million gallons of swap contracts that settle in future months.

As of June 30, 2014, to hedge a substantial majority of the purchase price associated with heating oil gallons anticipated to be sold to its price-protected customers, the Partnership held 0.1 million gallons of physical inventory and the following derivative instruments that settle in future months to match anticipated sales: 6.3 million gallons of swap contracts, 1.6 million gallons of call options, 4.0 million gallons of put options and 48.7 million net gallons of synthetic call options. 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, 2014, had 52.2 million gallons of purchased future contracts and 60.2 million gallons of sold future contracts that settle in future months. In addition to the previously described hedging instruments, to lock-in the differential between high sulfur home heating oil and ultra low sulfur diesel, the Partnership as of June 30, 2014, had 20.7 million gallons of corresponding purchased and sold swap contracts. To hedge its internal fuel usage for the remainder of fiscal 2014, the Partnership as of June 30, 2014, had 1.8 million gallons of swap contracts that settle in future months.

The Partnership’s derivative instruments are with the following counterparties: Bank of America, N.A., Bank of Montreal, Cargill, Inc., Citibank, N.A., JPMorgan Chase Bank, N.A., Key Bank, N.A., Regions Financial Corporation, Societe Generale, and Wells Fargo Bank, N.A. The Partnership assesses counterparty credit risk and considers it to be low. We maintain master netting arrangements that allow for the non-conditional offsetting of amounts receivable and payable with counterparties to help manage our risks and record derivative positions on a net basis. The Partnership generally does not receive cash collateral from its counterparties and does not restrict the use of cash collateral it maintains at counterparties. At June 30, 2015, the aggregate cash posted as collateral in the normal course of business at counterparties was $0.6 million. Positions with counterparties who are also parties to our revolving credit facility are collateralized under that facility. As of June 30, 2015, $2.5 million of hedge positions and payable amounts were secured under the credit facility.

FASB ASC 820-10 Fair Value Measurements and Disclosures, established a three-tier fair value hierarchy, which classified the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices for identical instruments in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. The Partnership’s Level 1 derivative assets and liabilities represent the fair value of commodity contracts used in its hedging activities that are identical and traded in active markets. The Partnership’s Level 2 derivative assets and liabilities represent the fair value of commodity contracts used in its hedging activities that are valued using either directly or indirectly observable inputs, whose nature, risk and class are similar. No significant transfers of assets or liabilities have been made into and out of the Level 1 or Level 2 tiers. All derivative instruments were non-trading positions and were either a Level 1 or Level 2 instrument. The Partnership had no Level 3 derivative instruments. 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
Asset Derivatives at June 30, 2015
Commodity contracts	Fair asset and fair liability value of derivative instruments	$	13,809		$	1,076	$	12,733
Commodity contracts	Long-term derivative assets included in the deferred charges and other assets, net balance		1,680			56		1,624

Commodity contract assets at June 30, 2015		$	15,489		$	1,132	$	14,357


Liability Derivatives at June 30, 2015
Commodity contracts	Fair liability and fair asset value of derivative instruments	$	15,963		$	890	$	15,073
Commodity contracts	Long-term derivative liabilities included in the other long-term liabilities balance		1,347			54		1,293

Commodity contract liabilities at June 30, 2015		$	17,310		$	944	$	16,366


Asset Derivatives at September 30, 2014
Commodity contracts	Fair asset and fair liability value of derivative instruments	$	26,263		$	2,328	$	23,935

Commodity contract assets at September 30, 2014		$	26,263		$	2,328	$	23,935


Liability Derivatives at September 30, 2014
Commodity contracts	Fair liability and fair asset value of derivative instruments	$	(36,279	)	$	—	$	(36,279	)

Commodity contract liabilities at September 30, 2014		$	(36,279	)	$	—	$	(36,279	)

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


(In thousands)									Gross Amounts Not Offset in the Statement of Financial Position
Offsetting of Financial Assets (Liabilities) and Derivative Assets (Liabilities)	Gross Assets Recognized		Gross Liabilities Offset in the Statement of Financial Position			Net Assets (Liabilities) Presented in the Statement of Financial Position			Financial Instruments		Cash Collateral Received		Net Amount
Fair asset value of derivative instruments	$	1,114	$	(890	)	$	224		$	—	$	—	$	224
Long-term derivative assets included in deferred charges and other assets, net		1,655		(1,321	)		334			—		—		334
Fair liability value of derivative instruments		12,694		(15,072	)		(2,378	)		—		—		(2,378	)
Long-term derivative liabilities included in other long-term liabilities, net		26		(27	)		(1	)						(1	)

Total at June 30, 2015	$	15,489	$	(17,310	)	$	(1,821	)	$	—	$	—	$	(1,821	)

Fair asset value of derivative instruments	$	2,342	$	—		$	2,342		$	—	$	—	$	2,342
Fair liability value of derivative instruments		23,921		(36,279	)		(12,358	)		—		—		(12,358	)

Total at September 30, 2014	$	26,263	$	(36,279	)	$	(10,016	)	$	—	$	—	$	(10,016	)


(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, 2015			Three Months Ended June 30, 2014			Nine Months Ended June 30, 2015			Nine Months Ended June 30, 2014
Closed Positions
Commodity contracts	Cost of product (a)	$	6,599		$	2,718		$	17,115		$	11,245
Commodity contracts	Cost of installations and service (a)	$	280		$	(82	)	$	1,625		$	(177	)
Commodity contracts	Delivery and branch expenses (a)	$	251		$	(5	)	$	1,716		$	(119	)

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

Open Positions
Commodity contracts	(Increase) / decrease in the fair value of derivative instruments	$	(5,415	)	$	(3,308	)	$	(9,756	)	$	(4,661	)

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, 2015		September 30, 2014
Product	$	27,066	$	39,802
Parts and equipment		19,531		19,438

Total inventory	$	46,597	$	59,240

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, 2015		September 30, 2014
Property and equipment	$	173,880	$	170,307
Less: accumulated depreciation		109,654		102,888

Property and equipment, net	$	64,226	$	67,419

7) Business Combination

During fiscal 2015, the Partnership acquired a propane dealer for an aggregate purchase price of approximately $1.1 million. The gross purchase price was allocated $0.3 million to intangible assets, $0.1 million to goodwill and $0.7 million to fixed assets. The acquired company’s operating results are included in the Partnership’s consolidated financial statements starting on its acquisition date, 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, 2014	$	209,331
Fiscal year 2015 business combination		73

Balance as of June 30, 2015	$	209,404

Intangibles, net

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


	June 30, 2015						September 30, 2014
	Gross						Gross
	Carrying		Accum.				Carrying		Accum.
	Amount		Amortization		Net		Amount		Amortization		Net
Customer lists	$	305,890	$	233,298	$	72,592	$	304,699	$	224,215	$	80,484
Trade names and other intangibles		24,207		4,720		19,487		24,070		3,771		20,299

Total	$	330,097	$	238,018	$	92,079	$	328,769	$	227,986	$	100,783

Amortization expense for intangible assets was $10.0 million for the nine months ended June 30, 2015, compared to $8.2 million for the nine months ended June 30, 2014.

9) Long-Term Debt and Bank Facility Borrowings


The Partnership’s debt is as follows	June 30, 2015				September 30, 2014
(in thousands):	Carrying Amount		Fair Value (a)		Carrying Amount		Fair Value (a)
Revolving Credit Facility Borrowings (b)	$	—	$	—	$	—	$	—
8.875% Senior Notes (c)		124,663		129,500		124,572		130,313

Total debt	$	124,663	$	129,500	$	124,572	$	130,313

Total short-term portion of debt (d)	$	25,000	$	25,000	$	—	$	—

Total long-term portion of debt	$	99,663	$	104,500	$	124,572	$	130,313

(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)

At June 30, 2015, the Partnership had a second amended and restated revolving credit facility with a bank syndicate comprised of fifteen participants whose maturity date was June 2017, or January 2019 if certain conditions of the facility termination date had been met. Under this agreement, the Partnership had the ability to borrow up to $300 million ($450 million during the heating season of December through April of each year) for working capital purposes (subject to certain borrowing base limitations and coverage ratios), including the issuance of up to $100 million in letters of credit.

On July 30, 2015, the Partnership entered into a third amended and restated asset based revolving credit facility agreement with a bank syndicate comprised of thirteen participants, which enables the Partnership to borrow up to $300 million ($450 million during the heating season of December through April of each year) on a revolving line of credit for working capital purposes (subject to certain borrowing base limitations and coverage ratios), provides for a $100 million five-year senior secured term loan (the “$100 million Term Loan”), allows for the issuance of up to $100 million in letters of credit, and extends the maturity date to July 2020. (See Note 14. Subsequent Events).

The Partnership can increase the revolving credit facility size by $100 million without the consent of the bank group. However, the bank group is not obligated to fund the $100 million increase. If the bank group elects not to fund the increase, the Partnership can add additional lenders to the group, with the consent of the Agent, which shall not be unreasonably withheld. Obligations under the third amended and restated credit facility are guaranteed by the Partnership and its subsidiaries and are secured by liens on substantially all of the Partnership’s assets including accounts receivable, inventory, general intangibles, real property, fixtures and equipment.

All amounts outstanding under the third amended and restated revolving credit facility become due and payable on the facility termination date of July 30, 2020. The $100 million Term Loan is repayable in quarterly payments of $2.5 million, plus an annual payment equal to 25% of the annual Excess Cash Flow as defined in the agreement (an amount not to exceed $15 million annually), less certain voluntary prepayments made during the year, with final payment at maturity.

The interest rate on the third amended and restated revolving line of credit and the term loan is based on a margin over LIBOR or a base rate.

The Commitment Fee on the unused portion of the revolving line of credit is 0.30% from December through April, and 0.20% from May through November.

The third amended and restated revolving credit facility requires the Partnership to meet certain financial covenants, including a fixed charge coverage ratio (as defined in the revolving credit facility agreement) of not less than 1.1 as long as the $100 million Term Loan is outstanding or revolving loan availability is less than 12.5% of the facility size. In addition, as long as the $100 million Term Loan is outstanding, a senior secured leverage ratio at any time cannot be more than 3.0 as calculated during the quarters ending June or September, and at any time no more than 4.5 as calculated during the quarters ending December or March.

Certain restrictions are also imposed by the agreement, including restrictions on the Partnership’s ability to incur additional indebtedness, to pay distributions to unitholders, to pay certain inter-company dividends or distributions, make investments, grant liens, sell assets, make acquisitions and engage in certain other activities.

(c)	The 8.875% Senior 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 $0.3 million at June 30, 2015.

On July 30, 2015, the Partnership and its co-issuer and wholly owned subsidiary SGFC delivered to the trustee of the indenture governing the 8.875% Senior Notes a notice of redemption to purchase for cash all of the outstanding $125 million in face amount of these notes at a redemption price of 104.438% plus any accrued but unpaid interest through the September 3, 2015, redemption date. (See Note 14. Subsequent Events, (b) above and (d) below)

(d)

As of June 30, 2015, the Partnership has classified $25 million of its 8.875% Senior Notes as a current liability reflecting the notice to redeem such notes, and the intent to repay using $25 million of current assets and the $100 million Term Loan provided in the third amended and restated revolving credit facility agreement.

At June 30, 2015, no amount was outstanding under the revolving credit facility in place, $2.5 million of hedge positions were secured, and $54.8 million of letters of credit were issued. At September 30, 2014, no amount was outstanding under the revolving credit facility, $14.9 million of hedge positions were secured, and $52.8 million of letters of credit were issued.

At June 30, 2015, availability was $232.2 million and the Partnership was in compliance with the revolving credit facility’s fixed charge coverage ratio. At September 30, 2014, availability was $149.6 million and the Partnership was in compliance with the revolving credit facility’s fixed charge coverage ratio.

10) Income Taxes

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

Income and losses of Star Gas Partners are allocated directly to the individual partners. Even though Star Gas Partners will generate non-qualifying Master Limited Partnership income through its corporate subsidiaries, cash received by Star Gas Partners from its corporate subsidiaries is generally included in the determination of qualified Master Limited Partnership income. All or a portion of such cash could be taxable as dividend income or as a capital gain to the individual partners. This could be the case even if Star Gas Partners used the cash received from its corporate subsidiaries for purposes such as the repurchase of Common Units, other types of capital transactions, or paying its own expenses rather than for distributions to its individual partners.

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

The current and deferred income tax expenses for the three and nine months ended June 30, 2015, and 2014 are as follows:


	Three Months Ended						Nine Months Ended
	June 30,						June 30,
(in thousands)	2015			2014			2015		2014
Income before income taxes	$	(13,970	)	$	(16,618	)	$	142,819	$	105,514

Current tax expense	$	(6,433	)	$	(7,888	)	$	51,339	$	34,550
Deferred tax expense		822			862			8,598		9,052

Total tax expense	$	(5,611	)	$	(7,026	)	$	59,937	$	43,602

As of January 1, 2015, Star Acquisitions, Inc., a wholly-owned subsidiary of the Partnership, had an estimated Federal net operating loss carry forward (“NOLs”) of approximately $6.1 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.

At June 30, 2015, we had unrecognized income tax benefits totaling $1.0 million including related accrued interest and penalties of $0.1 million. These unrecognized tax benefits are primarily the result of state tax uncertainties. If recognized, these tax benefits would be recorded as a benefit to the effective tax rate.

We believe that the total liability for unrecognized tax benefits will not materially change during the next 12 months ending June 30, 2016. Our continuing practice is to recognize interest related to income tax matters as a component of income tax expense. We file U.S. Federal income tax returns and various state and local returns. A number of years may elapse before an uncertain tax position is audited and finally resolved. For our Federal income tax returns we have four tax years subject to examination. In our major state tax jurisdictions of New York, Connecticut, Pennsylvania and New Jersey, we have four, four, four and five tax years, respectively, that are subject to examination. While it is often difficult to predict the final outcome or the timing of resolution of any particular uncertain tax position, based on our assessment of many factors including past experience and interpretation of tax law, we believe that our provision for income taxes reflect the most probable outcome. This assessment relies on estimates and assumptions and may involve a series of complex judgments about future events.

11) Supplemental Disclosure of Cash Flow Information


	Nine Months Ended
	June 30,
(in thousands)	2015		2014
Cash paid during the period for:
Income taxes, net	$	28,746	$	26,073
Interest	$	13,283	$	16,023

Non-cash investing activities:
Acquisition of NYC heating oil customer list	$	886	$	—

Non-cash financing activities:
Increase in interest expense—amortization of debt discount on 8.875% Senior Notes	$	91	$	83

12) Commitments and Contingencies

The Partnership’s operations are subject to the operating hazards and risks normally incidental to handling, storing and transporting and otherwise providing for use by consumers hazardous liquids such as home heating oil and propane. In the ordinary course of business the Partnership is a defendant in various legal proceedings and litigations. The Partnership records a liability when it is probable that a loss has been incurred and the amount is reasonably estimable. The Partnership maintains insurance policies with insurers in amounts and with coverages and deductibles we believe are reasonable and prudent. However, the Partnership cannot assure that this insurance will be adequate to protect it from all material expenses related to potential future claims. In the opinion of management the Partnership is not a party to any litigation which, individually or in the aggregate, could reasonably be expected to have a material adverse effect on the Partnership’s results of operations, financial position or liquidity.

13) Earnings (Loss) Per Limited Partner Unit

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

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


	Three Months Ended						Nine Months Ended
Basic and Diluted Earnings Per Limited Partner:	June 30,						June 30,
(in thousands, except per unit data)	2015			2014			2015		2014
Net income (loss)	$	(8,359	)	$	(9,592	)	$	82,882	$	61,912
Less General Partner’s interest in net income (loss)		(47	)		(54	)		469		349

Net income (loss) available to limited partners		(8,312	)		(9,538	)		82,413		61,563

Less dilutive impact of theoretical distribution of earnings under FASB ASC 260-10-45-60		—			—			13,128		9,152

Limited Partner’s interest in net income (loss) under FASB ASC 260-10-45-60	$	(8,312	)	$	(9,538	)	$	69,285	$	52,411

Per unit data:
Basic and diluted net income (loss) available to limited partners	$	(0.15	)	$	(0.17	)	$	1.44	$	1.07

Less dilutive impact of theoretical distribution of earnings under FASB ASC 260-10-45-60		—			—			0.23		0.16

Limited Partner’s interest in net income (loss) under FASB ASC 260-10-45-60	$	(0.15	)	$	(0.17	)	$	1.21	$	0.91

Weighted average number of Limited Partner units outstanding		57,282			57,468			57,286		57,482

14) Subsequent Events

Quarterly Distribution Declared

In July 2015, we declared a quarterly distribution of $0.095 per unit, or $0.38 per unit on an annualized basis, on all Common Units with respect to the third quarter of fiscal 2015, payable on August 7, 2015, to holders of record on July 30, 2015. In accordance with our Partnership Agreement, the amount of distributions in excess of the minimum quarterly distribution of $0.0675, are distributed 90% to Common Unit holders and 10% to the General Partner unit holders (until certain distribution levels are met), subject to the management incentive compensation plan. As a result, $5.4 million will be paid to the Common Unit holders, $0.1 million to the General Partner unit holders (including $0.09 million of incentive distribution as provided in our Partnership Agreement) and $0.09 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.

Third Amended and Restated Revolving Credit Facility Agreement

In the fourth quarter of fiscal year 2015, the Partnership entered into a third amended and restated five-year $300 million ($450 million during the heating season of December through April of each year) revolving credit facility agreement and a new $100 million five-year amortizing senior secured term loan. Funding for this new $100 million Term Loan is expected in the fourth quarter of fiscal 2015.

Election to Redeem 8.875% Senior Notes

In the fourth quarter of fiscal year 2015, the Partnership and SGFC delivered to Union Bank, N.A, the Trustee of the Issuers’ 8.875% Senior Notes due 2017 (the “Notes”) a notice of redemption to purchase for cash all of the outstanding $125.0 million in face amount of the Notes at a redemption price of 104.438% plus any accrued but unpaid interest thereon with a redemption date of September 3, 2015. The Trustee will also serve as the Paying Agent for the Redemption.

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 in this Report under the headings “Risk Factors” and “Business Strategy.” Important factors that could cause actual results to differ materially from our expectations (“Cautionary Statements”) are disclosed in this Report. 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.

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”), for the fiscal years ending September 30, 2011 through June 30, 2015, on a quarterly basis, is illustrated in the following chart (price per gallon):


	Fiscal 2015⁽¹⁾				Fiscal 2014⁽¹⁾				Fiscal 2013 ⁽¹⁾				Fiscal 2012				Fiscal 2011
Quarter Ended	Low		High		Low		High		Low		High		Low		High		Low		High
December 31	$	1.85	$	2.66	$	2.84	$	3.12	$	2.90	$	3.26	$	2.72	$	3.17	$	2.19	$	2.54
March 31		1.62		2.30		2.89		3.28		2.86		3.24		2.99		3.32		2.49		3.09
June 30		1.68		2.02		2.85		3.05		2.74		3.09		2.53		3.25		2.75		3.32
September 30						2.65		2.98		2.87		3.21		2.68		3.24		2.77		3.13

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

Impact on Liquidity of Wholesale Product Cost Volatility

Our liquidity is adversely impacted in times of increasing wholesale product costs, as we must use more cash to fund our hedging requirements and a portion of the increased levels of accounts receivable and inventory. Our liquidity is also adversely impacted at times by sudden and sharp decreases in wholesale product costs due to the increased margin requirements for futures contracts and collateral requirements for options and swaps that we use to manage market risks.

Weather Hedge Contract

Weather conditions have a significant impact on the demand for home heating oil and propane because customers depend on these products principally for space heating purposes. Actual weather conditions may 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.

The Partnership has entered into weather hedge contracts for the fiscal years 2014, 2015, 2016 and 2017 with Swiss Re, 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 within the hedge period is less than approximately 92.5% of the ten year average (the “Payment Threshold”). The hedge period runs from November 1 through March 31, taken as a whole, for each respective fiscal year and has a maximum payout of $12.5 million for each fiscal year. The Partnership did not record any benefit under its weather hedge contract during fiscal 2014 and has not recorded any benefit for the nine months ended June 30, 2015.

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 to twenty-four 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 costs and losses on a per gallon basis could be greater, thus reducing expected margins.

Price-Protected Customer Renewals

A substantial majority of the Partnership’s price-protected customers have agreements with us that are subject to annual renewal in the period between April and November of each fiscal year. If a significant number of these customers elect not to renew their price-protected agreements with us and do not continue as our customers under a variable price-plan, the Partnership’s near term profitability, liquidity and cash flow will be adversely impacted. In addition, our ability to maintain or increase our home heating oil and propane margins will depend on the renewal of these customers at attractive 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.

Acquisitions

On March 4, 2014, the Partnership completed the acquisition of Griffith Energy Services, Inc. (“Griffith”) of Columbia, Maryland, from Central Hudson Enterprises Corporation. The Partnership purchased 100% of the stock of Griffith for $97.7 million, consisting of $69.9 million paid for the long term assets and $27.8 million paid for working capital (net of $4.2 million of cash acquired). For the nine months ended June 30, 2014, Griffith’s results are included from its acquisition date of March 4, 2014.

On December 22, 2014, the Partnership entered into an agreement to deliver to and service certain home heating oil accounts of a company (in the New York City Metropolitan area) that was exiting the business. The agreement provides that the Partnership will make payments to the seller over the next three years, estimated to total $1.0 million, based upon the Partnership’s retention of the accounts. Separately, in January 2015 the Partnership acquired a propane dealership in Georgia for approximately $1.1 million, including net working capital of $0.1 million.

Income Taxes

Net Operating Loss Carry Forwards

The Partnership and its corporate subsidiaries file Federal and state income tax returns on a calendar year. As of January 1, 2015, our Federal Net Operating Loss carry forwards (“NOLs”) were $6.1 million, subject to annual limitations of between $1.0 million and $2.2 million 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, which will increase as tax depreciation and amortization decreases. 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
2015	$	26,291	$	34,348
2016		23,783		28,424
2017		21,000		19,958
2018		17,906		15,792
2019		15,662		12,485
2020		13,135		10,605

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.

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 losses


	Fiscal Year Ended
	2015							2014							2013
	Gross Customer				Net Gains /			Gross Customer				Net Gains /			Gross Customer				Net Gains /
	Gains		Losses		(Attrition)			Gains		Losses		(Attrition)			Gains		Losses		(Attrition)
First Quarter		27,400		23,100		4,300			25,700		22,700		3,000			26,100		24,400		1,700
Second Quarter		16,000		18,200		(2,200	)		16,800		16,700		100			13,900		19,300		(5,400	)
Third Quarter		7,400		14,000		(6,600	)		8,100		14,100		(6,000	)		7,100		13,600		(6,500	)
Fourth Quarter		—		—		—			17,500		18,700		(1,200	)		14,400		18,000		(3,600	)

Total		50,800		55,300		(4,500	)		68,100		72,200		(4,100	)		61,500		75,300		(13,800	)

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


	Fiscal Year Ended
	2015									2014									2013
	Gross Customer						Net Gains /			Gross Customer						Net Gains /			Gross Customer						Net Gains /
	Gains			Losses			(Attrition)			Gains			Losses			(Attrition)			Gains			Losses			(Attrition)
First Quarter		6.2	%		5.2	%		1.0	%		6.1	%		5.3	%		0.8	%		6.3	%		5.9	%		0.4	%
Second Quarter		3.6	%		4.1	%		(0.5	%)		3.9	%		3.9	%		0.0	%		3.3	%		4.6	%		(1.3	%)
Third Quarter		1.6	%		3.1	%		(1.5	%)		1.9	%		3.3	%		(1.4	%)		1.7	%		3.3	%		(1.6	%)
Fourth Quarter		—			—			—			4.1	%		4.4	%		(0.3	%)		3.5	%		4.3	%		(0.8	%)

Total		11.4	%		12.4	%		(1.0	%)		16.0	%		16.9	%		(0.9	%)		14.8	%		18.1	%		(3.3	%)

During the nine months ended June 30, 2015, the Partnership lost 4,500 accounts (net), or 1.0%, of our home heating oil and propane customer base, compared to 2,900 accounts lost (net), or 0.7% of our home heating oil and propane customer base, during the nine months ended June 30, 2014.

Excluding the Griffith acquisition, gross customer gains were lower by 3,500 accounts and gross customer losses were lower by 1,800 accounts year-over-year. We believe the decline in home heating oil prices drove a reduction in marketing leads and resulted in lower gross customer gains as well as lower gross customer losses. In addition, during the nine months ended June 30, 2014, the Partnership’s gross customer gains benefitted from a few competitors that experienced operational difficulties.

During the nine months ended June 30, 2015, we lost 1.3% of our home heating oil accounts to natural gas conversions versus 1.6% during the comparable periods for fiscal 2014 and fiscal 2013. Conversions to natural gas may continue as it remains less expensive than home heating oil on an equivalent BTU basis.

Consolidated Results of Operations

The following is a discussion of the consolidated results of operations of the Partnership and its subsidiaries and should be read in conjunction with the historical financial and operating data and notes thereto included elsewhere in this Quarterly Report.

Three Months Ended June 30, 2015

Compared to the Three Months Ended June 30, 2014

Volume

For the three months ended June 30, 2015, retail volume of home heating oil and propane decreased by 2.6 million gallons, or 5.6%, to 44.5 million gallons, compared to 47.1 million gallons for the three months ended June 30, 2014. The third quarter of the Partnership’s fiscal year is a non-heating season, and average temperatures are not as impactful to home heating oil and propane volume sales as during the heating season. 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, 2015 were 14.9% warmer than the three months ended June 30, 2014 and 22.4% warmer than normal, as reported by NOAA. For the twelve months ended June 30, 2015, net customer attrition for the base business was 1.3%. Due to various reasons, we believe that our customers are adopting conservation measures to use less of our products. The impact of any such conservation, along with any period-to-period differences in delivery scheduling, the timing of accounts added or lost during the fiscal years, equipment efficiency and other volume variances not otherwise described, are also included in the chart below under the heading “Other.” An analysis of the change in the retail volume of home heating oil and propane, which is based on management’s estimates, sampling and other mathematical calculations and certain assumptions, is found below:


(in millions of gallons)	Heating Oil and Propane
Volume - Three months ended June 30, 2014		47.1
Acquisitions		0.5
Impact of warmer temperatures		(7.3	)
Net customer attrition		(0.5	)
Other		4.7

Change		(2.6	)


Volume - Three months ended June 30, 2015		44.5

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, 2015 compared to the three months ended June 30, 2014:


	Three Months Ended
Customers	June 30, 2015			June 30, 2014
Residential Variable		35.1	%		38.0	%
Residential Price-Protected		52.2	%		48.0	%
Commercial/Industrial/Other		12.7	%		14.0	%

Total		100.0	%		100.0	%

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

Volume of other petroleum products decreased by 1.9 million gallons, or 7.5%, to 23.4 million gallons for the three months ended June 30, 2015, compared to 25.3 million gallons for the three months ended June 30, 2014. The volume decline was due to the loss of some high volume but low margin accounts.

Product Sales

For the three months ended June 30, 2015, product sales decreased $82.8 million, or 30.9%, to $184.9 million, compared to $267.7 million for the three months ended June 30, 2014, due to a decline in wholesale product costs of $1.0206 per gallon, or 34.2%, and a decline in total volume of 6.3%, slightly offset by higher per gallon gross profit margins.

Installations and Services

For the three months ended June 30, 2015, installation and service sales increased $1.9 million, or 3.2%, to $60.7 million, compared to $58.8 million for the three months ended June 30, 2014, due primarily to an increase in service sales in the base business of $1.8 million partially related to the expansion of the Partnership’s other service offerings.

Cost of Product

For the three months ended June 30, 2015, cost of product decreased $82.8 million, or 38.4%, to $133.1 million, compared to $215.8 million for the three months ended June 30, 2014, due largely to a $1.0206 per gallon, or 34.2%, decline in wholesale product cost and a decline in total volume of 6.3%.

Gross Profit—Product


	Three Months Ended
	June 30, 2015				June 30, 2014
Home Heating Oil and Propane	Amount (in millions)		Per Gallon		Amount (in millions)		Per Gallon
Volume		44.5				47.1

Sales	$	132.6	$	2.9811	$	184.7	$	3.9205
Cost	$	87.8	$	1.9735	$	139.9	$	2.9698


Gross Profit	$	44.8	$	1.0076	$	44.8	$	0.9507


Other Petroleum Products	Amount (in millions)		Per Gallon		Amount (in millions)		Per Gallon
Volume		23.4				25.3

Sales	$	52.3	$	2.2357	$	83.0	$	3.2821
Cost	$	45.3	$	1.9356	$	75.9	$	3.0020


Gross Profit	$	7.0	$	0.3001	$	7.1	$	0.2801


Total Product	Amount (in millions)				Amount (in millions)
Sales	$	184.9			$	267.7
Cost	$	133.1			$	215.8


Gross Profit	$	51.8			$	51.9

For the three months ended June 30, 2015, total product gross profit was $51.8 million, $0.1 million less than for the three months ended June 30, 2014, as the impact of higher home heating oil and propane margins was offset by a decline in home heating oil and propane volume.

Cost of Installations and Services

For the three months ended June 30, 2015, cost of installations and services increased by $2.8 million, or 5.6%, to $52.8 million, compared to $50.0 million for the three months ended June 30, 2014.

Total installation costs for the three months ended June 30, 2015 increased by $0.2 million, or 0.9%, to $17.7 million, compared to $17.5 million in installation costs for the three months ended June 30, 2014. Installation costs as a percentage of installation sales for the three months ended June 30, 2015 and the three months ended June 30, 2014 were 83.9% and 83.2%, respectively.

Service expenses increased to $35.1 million for the three months ended June 30, 2015, or 88.5% of service sales, versus $32.5 million, or 86.0% of service sales for the three months ended June 30, 2014. The increase in service expenses of $2.6 million was primarily due to the increase in service sales, the Partnership’s expansion of its other service offerings, and certain training initiatives. We experienced a combined gross profit from service and installation of $7.9 million for the three months ended June 30, 2015 compared to a combined gross profit of $8.8 million for the three months ended June 30, 2014. 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, 2015, the change in the fair value of derivative instruments resulted in a $5.4 million credit due to the expiration of certain hedged positions (a $1.0 million credit) and an increase in the market value for unexpired hedges (a $4.4 million credit).

During the three months ended June 30, 2014, the change in the fair value of derivative instruments resulted in a $3.3 million credit due to the expiration of certain hedged positions (a $1.6 million credit) and an increase in market value for unexpired hedges (a $1.7 million credit).

Delivery and Branch Expenses

For the three months ended June 30, 2015, delivery and branch expense decreased $1.8 million, or 2.7%, to $64.6 million, compared to $66.3 million for the three months ended June 30, 2014, as an acquisition related increase of $0.4 million was more than offset by a decline in the base business of $2.2 million. The base business year-over-year comparison was impacted by a $1.7 million charge recorded during the three months ended June 30, 2014 to correct understatements of certain sales and petroleum taxes and related penalties the majority of which related to years prior to fiscal 2014. The Partnership did not record a similar charge during the three months ended June 30, 2015.

Depreciation and Amortization

For the three months ended June 30, 2015, depreciation and amortization expense increased by $0.4 million, or 7.7%, to $6.2 million, compared to $5.8 million for the three months ended June 30, 2014 due to acquisitions.

General and Administrative Expenses

For the three months ended June 30, 2015, general and administrative expenses increased $1.0 million, to $6.1 million, from $5.1 million for the three months ended June 30, 2014, largely due to an increase in profit sharing expense of $0.5 million and higher legal and professional fees.

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

Finance Charge Income

For the three months ended June 30, 2015, finance charge income decreased by $0.8 million, or 30.9%, to $1.7 million compared to $2.5 million for the three months ended June 30, 2014. The decline in the wholesale cost of product led to lower retail selling prices and thus a decline in accounts receivable balances subject to a finance charge.

Interest Expense, Net

For the three months ended June 30, 2015, interest expense decreased $1.9 million, or 35.7%, to $3.5 million compared to $5.4 million for the three months ended June 30, 2014, due in part to a decrease in average working capital borrowings of $97.3 million. Working capital borrowings were lower due to a decline in sales for both the three and nine month periods driven by lower wholesale product costs. In addition, during the three months ended June 30, 2014, the Partnership recorded a $1.4 million charge to correct understatements arising from certain sales and petroleum tax audits that were previously contested.

Amortization of Debt Issuance Costs

For the three months ended June 30, 2015, amortization of debt issuance costs was unchanged at $0.4 million compared to the three months ended June 30, 2014.

Income Tax Benefit

For the three months ended June 30, 2015, Star’s income tax benefit decreased by $1.4 million to $5.6 million, from $7.0 million for the three months ended June 30, 2014, due to a decrease in income before income taxes of $2.6 million. The Partnership’s effective income tax rate was 40.2% for the three months ended June 30, 2015 compared to 42.3% for the three months ended June 30, 2014.

Net Loss

For the three months ended June 30, 2015, the net loss decreased $1.2 million, or 12.9% to $8.4 million, from $9.6 million for the three months ended June 30, 2014, due to a decrease in the pretax loss of $2.6 million which was reduced by a decline in the income tax benefit of $1.4 million.

Adjusted EBITDA

For the three months ended June 30, 2015, the Adjusted EBITDA loss increased by $0.9 million, or 11.2%, to $9.3 million as the impact of higher home heating oil and propane per gallon margins was more than offset by the decline in volume attributable to the 14.9% warmer weather and a decrease in service and installation profitability. In addition, the quarter to quarter comparison was favorably impacted by the absence of a $1.7 million charge recorded during the three months ended June 30, 2014 to correct understatements of certain sales and petroleum taxes and related penalties.

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)	2015			2014

Net loss	$	(8,359	)	$	(9,592	)
Plus:
Income tax benefit		(5,611	)		(7,026	)
Amortization of debt issuance cost		406			394
Interest expense, net		3,491			5,427
Depreciation and amortization		6,204			5,760

EBITDA (a)		(3,869	)		(5,037	)

(Increase) / decrease in the fair value of derivative instruments		(5,415	)		(3,308	)

Adjusted EBITDA (a)		(9,284	)		(8,345	)

Add / (subtract)
Income tax benefit		5,611			7,026
Interest expense, net		(3,491	)		(5,427	)
Provision for losses on accounts receivable		1,495			4,384
Decrease in accounts receivables		127,879			161,737
Decrease in inventories		4,110			11,560
Increase in customer credit balances		15,714			8,837
Change in deferred taxes		822			861
Change in other operating assets and liabilities		(50,285	)		(53,680	)

Net cash provided by operating activities	$	92,571		$	126,953


Net cash used in investing activities	$	(1,498	)	$	(1,471	)


Net cash used in financing activities	$	(5,552	)	$	(131,322	)

(a)

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 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;

•

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

•

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.

Nine Months Ended June 30, 2015

Compared to the Nine Months Ended June 30, 2014

Volume

For the nine months ended June 30, 2015, retail volume of home heating oil and propane increased by 22.9 million gallons, or 6.8%, to 361.7 million gallons, compared to 338.8 million gallons for the nine months ended June 30, 2014. 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, 2015 were equal to the nine months ended June 30, 2014 and 5.0% colder than normal, as reported by the National Oceanic and Atmospheric Administration (“NOAA”). For the twelve months ended June 30, 2015, net customer attrition for the base business was 1.3%. Due to various reasons, we believe that our customers are adopting conservation measures to use less of our products. The impact of any such conservation, along with any period-to-period differences in delivery scheduling, the timing of accounts added or lost during the fiscal years, equipment efficiency and other volume variances not otherwise described, are also included in the chart under the heading “Other.” An analysis of the change in the retail volume of home heating oil and propane, which is based on management’s estimates, sampling and other mathematical calculations and certain assumptions, is found below:


(in millions of gallons)	Heating Oil and Propane
Volume - Nine months ended June 30, 2014		338.7
Acquisitions		25.8
Impact of temperatures		(0.1	)
Net customer attrition		(5.6	)
Other		2.9

Change		23.0


Volume - Nine months ended June 30, 2015		361.7

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 nine months ended June 30, 2015 compared to the nine months ended June 30, 2014:


	Nine Months Ended
Customers	June 30, 2015			June 30, 2014
Residential Variable		38.1	%		40.0	%
Residential Price-Protected		48.0	%		45.9	%
Commercial/Industrial/Other		13.9	%		14.1	%

Total		100.0	%		100.0	%

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

Volume of other petroleum products increased by 16.1 million gallons, or 27.0%, to 76.0 million gallons for the nine months ended June 30, 2015, compared to 59.9 million gallons for the nine months ended June 30, 2014, largely due to the additional volume from the Griffith acquisition of 19.2 million gallons, which was partially offset by a decline in the base business of 3.1 million gallons. The volume decline was due to the loss of some high volume but low margin accounts.

Product Sales

For the nine months ended June 30, 2015, product sales decreased $245.1 million, or 15.6%, to $1.3 billion, compared to $1.6 billion for the nine months ended June 30, 2014, as the impact from an increase in total volume of 9.8% and higher per gallon gross profit margins was more than offset by a decline in wholesale product costs of $0.9778 per gallon, or 32.1%.

Installations and Services

For the nine months ended June 30, 2015, installation and service sales increased $12.9 million, or 7.7%, to $181.2 million, compared to $168.3 million for the nine months ended June 30, 2014, due to additional revenue from acquisitions of $10.0 million and an increase in the base business of $2.9 million.

Cost of Product

For the nine months ended June 30, 2015, cost of product decreased $308.9 million, or 25.4%, to $0.9 billion, compared to $1.2 billion for the nine months ended June 30, 2014, as an increase in total volume of 9.8% was more than offset by a 32.1% decline, or $0.9778 per gallon, in 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 nine months ended June 30, 2015 increased by $0.0964 per gallon, or 9.6%, to $1.1008 per gallon, from $1.0044 per gallon during the nine months ended June 30, 2014 due in part to the impact of the Griffith acquisition. In the base business, home heating oil and propane margins increased by $0.0830 per gallon or 8.3%. Over the last five fiscal years, on average, our home heating oil and propane margins have increased by $0.0204 per gallon annually. The expansion of the Partnership’s margins during the nine months June 30, 2015 is in excess of the historical average by $0.0626 per gallon in the base business. The Partnership was able to expand its per gallon margins due to the decline in per gallon wholesale product costs. In addition, numerous snow storms and the intensity of the winter weather conditions experienced during the second quarter of fiscal 2015, which drove an increase in operating and service costs, necessitated an increase in per gallon margins to help defray such additional operating expenses. Going forward, the Partnership cannot guarantee that the per gallon margins achieved during the nine months ended June 30, 2015 are sustainable. Product sales and cost of product include home heating oil, propane, other petroleum products and liquidated damages billings.


	Nine Months Ended
	June 30, 2015				June 30, 2014
Home Heating Oil and Propane	Amount (in millions)		Per Gallon		Amount (in millions)		Per Gallon
Volume		361.7				338.7

Sales	$	1,146.1	$	3.1683	$	1,370.1	$	4.0446
Cost	$	747.9	$	2.0675	$	1,029.9	$	3.0402


Gross Profit	$	398.2	$	1.1008	$	340.3	$	1.0044


Other Petroleum Products	Amount (in millions)		Per Gallon		Amount (in millions)		Per Gallon
Volume		76.0				59.9

Sales	$	179.8	$	2.3643	$	200.9	$	3.3547
Cost	$	157.2	$	2.0675	$	184.1	$	3.0739


Gross Profit	$	22.6	$	0.2968	$	16.8	$	0.2808


Total Product	Amount (in millions)				Amount (in millions)
Sales	$	1,325.9			$	1,571.1
Cost	$	905.1			$	1,214.0


Gross Profit	$	420.8			$	357.1

For the nine months ended June 30, 2015, total product gross profit increased by $63.7 million, or 17.8% to $420.8 million, compared to $357.1 million for the nine months ended June 30, 2014, due to an increase in home heating oil and propane volume ($23.1 million), the impact of higher home heating oil and propane margins ($34.8 million), and the additional gross profit from other petroleum products ($5.8 million).

Cost of Installations and Services

For the nine months ended June 30, 2015, cost of installations and services increased by $17.4 million, or 11.1%, to $173.8 million, compared to $156.4 million for the nine months ended June 30, 2014, reflecting an $8.6 million increase related to acquisitions and $8.8 million higher expenses in our base business.

Installation costs for the nine months ended June 30, 2015, rose by $2.9 million, or 5.6%, to $54.5 million, compared to $51.6 million in installation costs for the nine months ended June 30, 2014 due to acquisitions. Installation costs as a percentage of installation sales for the nine months ended June 30, 2015 and the nine months ended June 30, 2014 were 84.4% and 84.6%, respectively. Service expenses increased to $119.4 million for the nine months ended June 30, 2015, or 102.3% of service sales, versus $104.9 million, or 97.7% of service sales, for the nine months ended June 30, 2014. The higher service expense of $14.5 million reflects an acquisition related increase of $5.8 million and an increase in the base business of $8.7 million, or 8.3%. In addition to normal inflationary pressures on service expenses, the 5.8% colder temperatures experienced in the second quarter of fiscal 2015 drove an increase in the amount of service work required to ensure our customers’ heating systems were operational. The numerous snow storms in certain areas of our footprint hampered productivity and also drove an increase in service costs as the additional service work was performed at premium labor rates. In addition, the Partnership’s expansion of its service offerings resulted in an increase in service costs. We experienced a combined gross profit from service and installation of $7.4 million for the nine months ended June 30, 2015, compared to a combined gross profit of $11.8 million for the nine months ended June 30, 2014. 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, 2015, the change in the fair value of derivative instruments resulted in a $9.8 million credit due to the expiration of certain hedged positions (an $11.7 million credit) and a decrease in the market value for unexpired hedges (a $1.9 million charge).

During the nine months ended June 30, 2014, the change in the fair value of derivative instruments resulted in a $4.7 million credit due to the expiration of certain hedged positions (a $5.8 million credit) and a decrease in the market value for unexpired hedges (a $1.1 million charge).

Delivery and Branch Expenses

For the nine months ended June 30, 2015, delivery and branch expense increased $22.3 million, or 9.8%, to $249.5 million, compared to $227.2 million for the nine months ended June 30, 2014, due to an acquisition-related increase of $17.6 million and an increase in the base business of $4.7 million due in part to the colder temperatures experienced during the second quarter of fiscal 2015. The year over year comparison was favorably impacted by a $1.7 million charge recorded during the nine months ended June 30, 2014 to correct understatements of certain sales and petroleum taxes and related penalties the majority of which related to years prior to fiscal 2014.

On a cents per gallon basis, delivery and branch expenses for the nine months ended June 30, 2015, decreased $0.0036, or 0.6%, to $0.5838, compared to $0.5874 for the nine months ended June 30, 2014. In the base business, delivery and branch expenses increased by $0.0191 per gallon, or 3.2% to $0.6065 for the nine months ended June 30, 2015. The additional volume delivered during the second fiscal quarter (due to colder weather) was at premium labor rates, and the numerous snow storms created operational inefficiencies which also led to a higher than expected cents per gallon of delivery and branch expenses. This was offset by lower per gallon operating expenses of acquisitions.

Depreciation and Amortization

For the nine months ended June 30, 2015, depreciation and amortization expense increased by $3.5 million, or 23.6%, to $18.6 million, compared to $15.0 million for the nine months ended June 30, 2014 largely due to the Griffith acquisition.

General and Administrative Expenses

For the nine months ended June 30, 2015, general and administrative expenses increased $2.1 million, or 12.3%, to $19.1 million, from $17.0 million for the nine months ended June 30, 2014, due largely to an increase in profit sharing expense of $1.3 million and $0.5 million in legal and professional fees relating to an abandoned debt refinancing.

Finance Charge Income

For the nine months ended June 30, 2015, finance charge income decreased $1.7 million, or 28.7% to $4.0 million, compared to $5.7 million for the nine months ended June 30, 2014. The decline in the wholesale cost of product led to lower retail selling prices and thus a decline in accounts receivable balances subject to a finance charge.

Interest Expense, Net

For the nine months ended June 30, 2015, interest expense decreased $2.5 million, or 19.2%, to $10.8 million compared to $13.3 million for the nine months ended June 30, 2014 primarily due in part to the decrease in average working capital borrowings of $90.1 million. Working capital borrowings were lower due to lower wholesale product costs. In addition, during the nine months ended June 30, 2014, the Partnership recorded a $1.4 million charge to correct understatements arising from certain sales and petroleum tax audits that were previously contested.

Amortization of Debt Issuance Costs

For the nine months ended June 30, 2015 and June 30, 2014, amortization of debt issuance costs was unchanged at $1.2 million.

Income Tax Expense

For the nine months ended June 30, 2015, income tax expense increased by $16.3 million to $59.9 million from $43.6 million for the nine months ended June 30, 2014, due to an increase in pretax income of $37.3 million and an increase in the effective income tax rate. The Partnership’s effective tax rate was 42.0% for the nine months ended June 30, 2015 versus 41.3% for the nine months ended June 30, 2014.

Net Income

For the nine months ended June 30, 2015, net income increased $21.0 million, or 33.9% to $82.9 million, from $61.9 million for the nine months ended June 30, 2014, as the increase in pretax income of $37.3 million was greater than the increase in income tax expense of $16.4 million.

Adjusted EBITDA

For the nine months ended June 30, 2015, Adjusted EBITDA increased by $33.2 million, or 25.5%, to $163.6 million as the impact of higher home heating oil and propane per gallon margins and acquisitions more than offset higher operating and service costs largely attributable to the colder temperatures and numerous snow storms in the second fiscal quarter and the volume decline in the base business attributable to net customer attrition for the twelve months ended June 30, 2015.

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:


	Nine Months Ended June 30,
(in thousands)	2015			2014

Net income	$	82,882		$	61,912
Plus:
Income tax expense		59,937			43,602
Amortization of debt issuance cost		1,209			1,205
Interest expense, net		10,767			13,324
Depreciation and amortization		18,579			15,036

EBITDA (a)		173,374			135,079

(Increase) / decrease in the fair value of derivative instruments		(9,756	)		(4,661	)

Adjusted EBITDA (a)		163,618			130,418

Add / (subtract)
Income tax expense		(59,937	)		(43,602	)
Interest expense, net		(10,767	)		(13,324	)
Provision for losses on accounts receivable		5,062			8,862
Increase in accounts receivables		(17,730	)		(78,276	)
Decrease in inventories		12,691			24,706
Decrease in customer credit balances		(26,595	)		(43,588	)
Change in deferred taxes		8,598			9,051
Change in other operating assets and liabilities		21,231			11,006

Net cash provided by operating activities	$	96,171		$	5,253


Net cash used in investing activities	$	(6,084	)	$	(104,321	)


Net cash provided by (used in) financing activities	$	(16,438	)	$	21,126

(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.

During the nine months ended June 30, 2015, cash provided by operating activities increased by $90.9 million to $96.2 million, when compared to $5.3 million of cash provided by operating activities during the nine months ended June 30, 2014, reflecting a $15.2 million increase in cash generated from operations, a favorable change in cash relating to accounts receivable of $77.5 million (including customer credit balances), an increase in accrued income taxes of $12.6 million and other net decreases of $14.4 million. The significant decline in the cost of liquid product resulted in a lower level of accounts receivable, lower inventory levels and lower trade payables. The Partnership expects to pay its accrual for income taxes over the next nine months.

Investing Activities

Our capital expenditures for the nine months ended June 30, 2015 totaled $5.2 million, as we invested in computer hardware and software ($1.3 million), refurbished certain physical plants ($0.6 million), expanded our propane operations ($2.2 million) and made additions to our fleet and other equipment ($1.1 million). We also completed one acquisition for $1.1 million and allocated $0.3 million of the gross purchase price to intangible assets, $0.1 million to goodwill and $0.7 million to fixed assets.

Our capital expenditures for the nine months ended June 30, 2014 totaled $6.5 million, as we invested in computer hardware and software ($1.3 million), refurbished certain physical plants ($1.2 million), expanded our propane operations ($2.4 million) and made additions to our fleet and other equipment ($1.6 million). We also completed the Griffith acquisition for $98.7 million and allocated $52.4 million of the gross purchase price to intangible assets (including $8.0 million to goodwill), $17.5 million to fixed assets, $1.8 million to other long-term assets and $27.1 million to working capital, net of cash acquired of $4.2 million.

Financing Activities

During the nine months ended June 30, 2015, we borrowed $12.3 million under our credit facility and subsequently repaid $12.3 million. We also paid distributions of $15.5 million to our Common Unit holders, $0.281 million to our General Partner unit holders (including $0.215 million of incentive distributions as provided in our Partnership Agreement) and repurchased 0.123 million units for $0.7 million in connection with our unit repurchase plan.

During the nine months ended June 30, 2014, we borrowed $195.5 million under our revolving credit facility and repaid $155.9 million. We also paid distributions of $14.51 million to our Common Unit holders, $0.23 million to our General Partner unit holders (including $0.16 million of incentive distributions as provided in our Partnership Agreement) and repurchased 0.25 million units for $1.3 million in connection with our unit repurchase plan.

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, 2015 ($122.6 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. As of June 30, 2015, we had no borrowings under our revolving credit facility and $54.8 million in letters of credit were outstanding, primarily for current and future insurance reserves and our ability to borrow was reduced by $2.5 million to secure hedges with the bank group.

In July 2015, we entered into a third amended and restated asset-based revolving credit facility, which expires in July 2020 and provides us with the ability to borrow up to $300 million ($450 million during the heating season from December through April of each year) for working capital purposes (subject to certain borrowing base limitations and coverage ratios), including the issuance of up to $100 million in letters of credit. The amended and restated credit facility also provides for a $100 million five year term loan (Note 9(b) to our notes to Condensed Consolidated Financial Statements (unaudited) under Item 1.). Proceeds from the term loan will be used to redeem the Partnership’s 8.875% Senior Notes due 2017 (see below). We can increase the asset-based revolving credit 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.

On July 30, 2015 the Partnership announced that it had elected to redeem $125.0 million of its outstanding 8.875% Senior Notes due in 2017 at a price of 104.438% plus accrued interest through the redemption date of September 3, 2015. The Partnership intends to use the proceeds of the aforementioned bank term loan of $100 million and cash on hand to redeem the 8.875% Senior Notes. Some of the cash that will be used to redeem the 8.875% Senior Notes will be received by Star Gas Partners in the form of a dividend from its corporate subsidiaries, and may be taxable to individual partners. As of June 30, 2015, the Partnership has classified $25 million of its 8.875% Senior Notes as a current liability reflecting the notice to redeem such notes and the $100 million term loan provided in the third amended and restated bank facility.

Under the terms of the third amended and restated credit facility, we must maintain at all times Availability (borrowing base less amounts borrowed and letters of credit issued) of 12.5% of the maximum facility size and a fixed charge coverage ratio of not less than 1.1, while the term loan is outstanding. As of June 30, 2015, Availability, as defined in the revolving credit facility agreement, was $232.2 million and we were in compliance with this fixed charge coverage ratio.

Maintenance capital expenditures for the remainder of fiscal 2015 are estimated to be approximately $1.4 million, excluding the capital requirements for leased fleet. In addition, we plan to invest an additional $0.7 million in our propane operations. Distributions for the balance of fiscal 2015, at the current quarterly level of $0.095 per unit, would result in an aggregate of approximately $5.4 million to Common Unit holders, $0.1 million to our general partner (including $0.09 million of incentive distribution as provided for in our Partnership Agreement) and $0.09 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. While the Partnership is not obligated to make a minimum required contribution to its two frozen defined benefit pension plans in fiscal year 2015, it is expected that a $0.6 million pension contribution may be made before the end of fiscal 2015. Two underfunded multi-employer pension plans to which we contribute, one that includes two hundred of our current employees and the other that includes less than ten of our current employees, have been classified as carrying “red zone” status, indicating that they are less than 65% funded. We could be assessed our share of unfunded liabilities should we terminate participation in these plans, should there be a mass employer withdrawal from these plans, or if the plans become insolvent or otherwise terminate. We are currently evaluating an alternate funding option adopted by the trustees of the larger of the two “red zone” status plans to which we contribute that we expect would require us to technically withdraw from and then re-enter the plan, and pay an amount determined to be our share of the plan‘s unfunded liability, interest free, over a period of at least twenty-five years. If we agree to this remediation plan, we expect we will be required to record a non-cash charge to our income statement equal to the present value of the series of cash payments. There is no certainty, however, whether we will succeed in reaching an agreement with the plan trustees on such an alternate funding option. In addition, we intend to continue to repurchase Common Units pursuant to our unit repurchase plan and seek attractive acquisition opportunities within the Availability constraints of our revolving credit facility and funding resources.

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, 2014, Form 10-K disclosure and therefore, the table has not been included in this Form 10-Q.

Recent Accounting Pronouncements

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

•

ASU No. 2014-09, Revenue from Contracts with Customers.

•

ASU No. 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs.

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, 2015, we had outstanding borrowings totaling $125.0 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, 2015, the fair market value of these outstanding derivatives would increase by $6.0 million to a positive value of $4.2 million; and conversely a hypothetical ten percent decrease in the cost of product would decrease the fair market value of these outstanding derivatives by $(4.6) million to a negative value of $(6.4) million.

Item 4.

Controls and Procedures

a) Evaluation of disclosure controls and procedures.

The General Partner’s chief executive officer and its chief 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, 2015. Based on that evaluation, such chief executive officer and chief financial officer concluded that the Partnership’s disclosure controls and procedures were effective as of June 30, 2015 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 chief executive and chief 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.

On March 4, 2014, the Partnership completed the acquisition of Griffith Energy Services, Inc. (“Griffith”). The Partnership completed the integration of Griffith’s operations with the Partnership’s internal control systems as of June 30, 2015.

c) Other

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 chief executive officer and chief financial officer of our general partner have concluded, as of June 30, 2015, 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 in Part I Item 1A. “Risk Factors” in our Fiscal 2014 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.

Our obligation to fund multi-employer pension plans to which we contribute may have an adverse impact on us.

We participate in a number of multi-employer pension plans for current and former union employees covered under collective bargaining agreements. The risks of participating in multi-employer plans are different from single-employer plans in that assets contributed are pooled and may be used to provide benefits to current and former employees of other participating employers. Several factors could cause us to make significantly higher future contributions to these plans, including the funding status of the plan, unfavorable investment performance, insolvency or withdrawal of participating employers, changes in demographics and increased benefits to participants. Several of these multi-employer plans to which we contribute are underfunded, meaning that the value of such plans’ assets are less than the actuarial value of the plans’ benefit obligations. Two underfunded plans to which we contribute, one that includes two hundred of our current employees and the other that includes less than ten of our current employees, have been classified as carrying “red zone” status, indicating that they are less than 65% funded. We could be assessed our share of unfunded liabilities should we terminate participation in these plans, should there be a mass employer withdrawal from these plans, or if the plans become insolvent or otherwise terminate. We are currently evaluating an alternate funding option adopted by the trustees of the larger of the two “red zone” status plans to which we contribute that we expect would require us to technically withdraw from and then re-enter the plan, and pay an amount determined to be our share of the plan’s unfunded liability, interest free, over a period of at least twenty-five years. If we agree to this remediation plan, we expect we will be required to record a non-cash charge to our income statement equal to the present value of the series of cash payments. There is no certainty, however, whether we will succeed in reaching an agreement with the plan trustees on such an alternate funding option. While we currently have no intention of permanently terminating our participation in an underfunded plan and while our participation in underfunded pension plans have not significantly impacted our financial performance in the past, there can be no assurance that we will not be required to record material withdrawal liabilities or be required to make material cash contributions in the future to one or more underfunded plans, whether as a result of withdrawing from a plan, or of agreeing to any alternate funding option, or due to any of the other risks associated with being a participating employer in an underfunded plan. Any of these events could negatively impact our financial performance in the applicable period.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

Not applicable.

Item 6.

Exhibits

(a)	Exhibits Included Within:


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

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

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

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

101		The following materials from the Star Gas Partners, L.P. Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, formatted in Extensible Business Reporting Language (XBRL): (i) the Condensed Consolidated Balance Sheets, (ii) the Condensed Consolidated Statements of Operations, (iii) the Condensed Consolidated Statements of Comprehensive Income, (iv) the Condensed Consolidated Statements of Partners’ Capital, (v) the Condensed Consolidated Statements of Cash Flows and (vi) related notes.

101.INS		XBRL Instance Document.

101.SCH		XBRL Taxonomy Extension Schema Document.

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document.

101.LAB		XBRL Taxonomy Extension Label Linkbase Document.

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document.

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document.

SIGNATURE

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


Star Gas Partners, L.P.
(Registrant)

By:		Kestrel Heat LLC AS GENERAL PARTNER


Signature	Title	Date

/s/ Richard F. Ambury	Executive Vice President, Chief Financial Officer, Treasurer and Secretary Kestrel Heat LLC (Principal Financial Officer)	August 3, 2015
Richard F. Ambury		August 3, 2015

Signature	Title	Date

/s/ Richard G. Oakley	Senior Vice President - Controller Kestrel Heat LLC (Principal Accounting Officer)	August 3, 2015
Richard G. Oakley		August 3, 2015