Edgar Filing: STAR GAS PARTNERS LP

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Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended December 31, 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 January 31, 2016, the registrant had 57,279,052 Common Units outstanding.

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

INDEX TO FORM 10-Q


	Page
Part I Financial Information
Item 1 - Condensed Consolidated Financial Statements
Condensed Consolidated Balance Sheets as of December 31, 2015 (unaudited) and September 30, 2015		3
Condensed Consolidated Statements of Operations (unaudited) for the three months ended December 31, 2015 and December 31, 2014		4
Condensed Consolidated Statements of Comprehensive Income (unaudited) for the three months ended December 31, 2015 and December 31, 2014		5
Condensed Consolidated Statement of Partners’ Capital (unaudited) for the three months ended December 31, 2015		6
Condensed Consolidated Statements of Cash Flows (unaudited) for the three months ended December 31, 2015 and December 31, 2014		7
Notes to Condensed Consolidated Financial Statements (unaudited)		8-18
Item 2 - Management’s Discussion and Analysis of Financial Condition and Results of Operations		19-31
Item 3 - Quantitative and Qualitative Disclosures About Market Risk		32
Item 4 - Controls and Procedures		32-33

Part II Other Information:
Item 1 - Legal Proceedings		33
Item 1A - Risk Factors		33
Item 2 - Unregistered Sales of Equity Securities and Use of Proceeds		33
Item 6 - Exhibits		34
Signatures		35

Part I. FINANCIAL INFORMATION

Item 1.

Condensed Consolidated Financial Statements

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS


	December 31,			September 30,
(in thousands)	2015			2015
	(unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	86,890		$	100,508
Receivables, net of allowance of $6,287 and $6,713, respectively		112,141			89,230
Inventories		64,881			55,671
Fair asset value of derivative instruments		405			935
Weather hedge contract receivable		12,500			—
Current deferred tax assets, net		37,460			37,832
Prepaid expenses and other current assets		24,290			25,135

Total current assets		338,567			309,311


Property and equipment, net		69,687			68,123
Goodwill		212,676			211,045
Intangibles, net		107,332			107,317
Deferred charges and other assets, net		12,361			11,236

Total assets	$	740,623		$	707,032


LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Accounts payable	$	21,624		$	25,322
Fair liability value of derivative instruments		21,523			12,819
Current maturities of long-term debt		10,000			10,000
Accrued expenses and other current liabilities		107,486			107,745
Unearned service contract revenue		55,291			44,419
Customer credit balances		88,798			78,207

Total current liabilities		304,722			278,512


Long-term debt		90,000			90,000
Long-term deferred tax liabilities, net		22,028			21,524
Other long-term liabilities		27,123			27,110

Partners’ capital
Common unitholders		319,238			312,713
General partner		(325	)		(283	)
Accumulated other comprehensive loss, net of taxes		(22,163	)		(22,544	)

Total partners’ capital		296,750			289,886

Total liabilities and partners’ capital	$	740,623		$	707,032

See accompanying notes to condensed consolidated financial statements.

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS


	Three Months Ended December 31,
(in thousands, except per unit data - unaudited)	2015			2014

Sales:
Product	$	252,950		$	435,012
Installations and services		66,105			64,205

Total sales		319,055			499,217
Cost and expenses:
Cost of product		150,102			309,249
Cost of installations and services		62,912			60,683
(Increase) decrease in the fair value of derivative instruments		5,536			8,290
Delivery and branch expenses		64,194			78,834
Depreciation and amortization expenses		6,766			6,158
General and administrative expenses		6,420			6,056
Finance charge income		(521	)		(826	)

Operating income		23,646			30,773
Interest expense, net		(1,859	)		(3,460	)
Amortization of debt issuance costs		(312	)		(400	)

Income before income taxes		21,475			26,913
Income tax expense		9,417			11,359

Net income	$	12,058		$	15,554
General Partner’s interest in net income		68			88

Limited Partners’ interest in net income	$	11,990		$	15,466



Basic and diluted income per Limited Partner Unit (1):	$	0.19		$	0.24


Weighted average number of Limited Partner units outstanding:
Basic and Diluted		57,281			57,294

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

See accompanying notes to condensed consolidated financial statements.

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


	Three Months Ended December 31,
(in thousands - unaudited)	2015			2014

Net income	$	12,058		$	15,554

Other comprehensive income:
Unrealized gain on pension plan obligation (1)		648			556
Tax effect of unrealized gain on pension plan		(267	)		(230	)

Total other comprehensive income		381			326


Total comprehensive income	$	12,439		$	15,880

(1)	This item is 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, 2015		57,282			326	$	312,713		$	(283	)	$	(22,544	)	$	289,886

Net income		—			—		11,990			68			—			12,058
Unrealized gain on pension plan obligation		—			—		—			—			648			648
Tax effect of unrealized gain on pension plan		—			—		—			—			(267	)		(267	)
Distributions		—			—		(5,442	)		(110	)		—			(5,552	)
Retirement of units (1)		(3	)		—		(23	)		—			—			(23	)

Balance as of December 31, 2015 (unaudited)		57,279			326	$	319,238		$	(325	)	$	(22,163	)	$	296,750

(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


	Three Months Ended December 31,
(in thousands - unaudited)	2015			2014

Cash flows provided by (used in) operating activities:
Net income	$	12,058		$	15,554

Adjustment to reconcile net income to net cash provided by (used in) operating activities:
(Increase) decrease in fair value of derivative instruments		5,536			8,290
Depreciation and amortization		7,078			6,558
Provision for losses on accounts receivable		(636	)		236
Change in deferred taxes		609			230
Change in weather hedge contract receivable		(12,500	)		—
Changes in operating assets and liabilities:
Increase in receivables		(22,263	)		(58,241	)
Increase in inventories		(9,064	)		(8,633	)
(Increase) decrease in other assets		1,091			(5,565	)
Increase (decrease) in accounts payable		(3,020	)		20,261
Increase (decrease) in customer credit balances		10,427			(5,862	)
Increase in other current and long-term liabilities		13,883			13,752

Net cash provided by (used in) operating activities		3,199			(13,420	)


Cash flows provided by (used in) investing activities:
Capital expenditures		(3,206	)		(1,772	)
Proceeds from sales of fixed assets		23			88
Acquisitions		(7,615	)		—

Net cash used in investing activities		(10,798	)		(1,684	)


Cash flows provided by (used in) financing activities:
Distributions		(5,552	)		(5,098	)
Unit repurchases		(23	)		(691	)
Customer retainage payments		(235	)		—
Payments of debt issue costs		(209	)		—

Net cash used in financing activities		(6,019	)		(5,789	)


Net decrease in cash and cash equivalents		(13,618	)		(20,893	)

Cash and cash equivalents at beginning of period		100,508			48,999

Cash and cash equivalents at end of period	$	86,890		$	28,106

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. Including our propane locations, we serve customers in the more northern and eastern states within the Northeast, Central and Southeast U.S. regions.

The Partnership is organized as follows:

•

The Partnership is a master limited partnership, which as of December 31, 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., a Minnesota corporation (“SA”), that owns 100% of Petro Holdings, Inc., a Minnesota corporation (“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, Central and Southeast region retail distributor of home heating oil and propane that as of December 31, 2015, served approximately 458,000 full-service residential and commercial home heating oil and propane customers. Petro also sold diesel fuel, gasoline and home heating oil to approximately 78,000 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 25,000 customers.

•

Petroleum Heat and Power Co., Inc., a Minnesota corporation (“PH&P”) is a 100% owned subsidiary of the Partnership. PH&P is the borrower and the Partnership is the guarantor of the third amended and restated credit agreement’s $100 million five-year senior secured term loan and the $300 million ($450 million during the heating season of December through April of each year) revolving credit facility, both due July 30, 2020. (See Note 9—Long-Term Debt and Bank Facility Borrowings)

2) Summary of Significant Accounting Policies

Basis of Presentation

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

The financial information included herein is unaudited; however, such information reflects all adjustments (consisting solely of normal recurring adjustments), which are, in the opinion of management, necessary for the fair statement of financial condition and results for the interim periods. Due to the seasonal nature of the Partnership’s business, the results of operations and cash flows for the three month period ended December 31, 2015, and December 31, 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, 2015.

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.

Weather Hedge Contract

To partially mitigate the adverse effect of warm weather on cash flows, the Partnership has used weather hedge contracts for a number of years. Weather hedge contracts are recorded in accordance with the intrinsic value method defined by the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 815-45-15 Derivatives and Hedging, Weather Derivatives (EITF 99-2). The premium paid is included in the caption prepaid expenses and other current assets in the accompanying balance sheets and amortized over the life of the contract, with the intrinsic value method applied at each interim period.

For fiscal years 2016 and 2017 the Partnership has a weather hedge contract with Swiss Re under which the Partnership is entitled to receive a payment of $35,000 per heating degree-day shortfall, when the accumulated number of heating degree-days in the entire hedge period is less than approximately 92.5% of the ten year average, the Payment Threshold as defined in the contract. The hedge covers the five month period from November 1, through March 31, taken as a whole, for each respective fiscal year. The ultimate amount due to the Partnership (if any) is based on the entire five month accumulated calculation for the hedge period and has a maximum payout of $12.5 million for each respective fiscal year. In accordance with ASC 815-45-15, as of December 31, 2015, the Partnership recorded a credit of $12.5 million under this contract that reduced delivery and branch expenses. The final credit (if any) for fiscal 2016 may be lower than this amount depending on the actual heating degree-days recorded in the period January 1, 2016 through March 31, 2016. If the heating degree-days in this period approximate normal, the credit will be reduced to approximately $5.2 million. If temperatures in this period are colder than expected, then the additional heating degree-days could reduce the credit further, possibly even to zero. Temperatures recorded for January 2016, were slightly warmer than expected.

New England Teamsters and Trucking Industry Pension Fund (“the NETTI Fund”) Liability

As of December 31, 2015 we had $0.1 million and $17.6 million balances included in the captions accrued expenses and other current liabilities and other long-term liabilities, respectively, on our condensed consolidated balance sheet representing the remaining balance of the NETTI withdrawal liability. Based on the borrowing rates currently available to the Partnership for long-term financing of a similar maturity, the fair value of the NETTI withdrawal liability as of December 31, 2015 was $16.0 million. We utilized Level 2 inputs in the fair value hierarchy of valuation techniques to determine the fair value of this liability.

Recent Accounting Pronouncements

In May 2014, the 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 No. 2015-03 will be limited to the presentation of debt issuance cost on its balance sheet.

In July 2015, the FASB issued ASU No. 2015-11, Simplifying the Measurement of Inventory. The update changes the measurement principle for inventory from the lower of cost or market to the lower of cost and net realizable value. This new guidance is effective for our annual reporting period beginning in the first quarter of fiscal 2018, with early adoption permitted. The Partnership does not expect ASU No. 2015-11 to have a material impact on its consolidated financial statements and related disclosures.

In September 2015, the FASB issued ASU No. 2015-16, Simplifying the Accounting for Measurement-Period Adjustments, which requires an acquiring entity to recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The acquiring entity is required to record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. In addition, the acquiring entity is to present separately on the face of its income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods as if the adjustment to the provisional amounts had been recognized as of the acquisition date. This new guidance is effective for our annual reporting period beginning in the first quarter of fiscal 2017. The Partnership does not expect ASU No. 2015-16 to have a material impact on its consolidated financial statements and related disclosures.

In November 2015, FASB issued ASU 2015-17, Income Taxes - Balance Sheet Classification of Deferred Taxes, which eliminates the requirement for companies to present deferred tax assets and liabilities as current and non-current in a classified balance sheet. Instead, companies will be required to classify all deferred tax assets and liabilities as non-current. This new guidance is effective for our annual reporting period beginning in the first quarter of fiscal 2018, with early adoption permitted. The standard permits the use of either the prospective or retrospective transition method. The Partnership is evaluating the effect that ASU No. 2015-17 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.

3) Common Unit Repurchase and Retirement

In July 2012, the Board authorized the repurchase of up to 3.0 million of the Partnership’s Common Units (“Plan III”). In July 2013, the Board authorized 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 third amended and restated credit agreement dated July 30, 2015, in order to repurchase Common Units we must maintain Availability (as defined in the amended and restated credit agreements) of $45 million, 15.0% of the facility size of $300 million (assuming the non-seasonal aggregate commitment is in effect) 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 three months ended December 31, 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 2015 total (c)		3,742	$	4.72		2,302


Plan III - October 2015		—	$	—		2,302
Plan III - November 2015		—	$	—		2,302
Plan III - December 2015		3	$	7.02		2,299

Plan III - First quarter fiscal year 2016 total		3	$	7.02		2,299

(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 1.4 million common units acquired in a private transaction.

4) Derivatives and Hedging—Disclosures and Fair Value Measurements

FASB ASC 815-10-05 Derivatives and Hedging, established accounting and reporting standards requiring that derivative instruments be recorded at fair value and included in the consolidated balance sheet as assets or liabilities, along with qualitative disclosures regarding the derivative activity. 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 December 31, 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: 10.1 million gallons of swap contracts, 8.2 million gallons of call options, 6.0 million gallons of put options, and 98.9 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 December 31, 2015, had 1.4 million gallons of long swap contracts, 24.6 million gallons of long future contracts, and 57.1 million gallons of short 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 December 31, 2015, had 8.4 million gallons of spread contracts (simultaneous long and short positions). To hedge its internal fuel usage and other related activities for fiscal 2016, the Partnership, as of December 31, 2015, had 4.4 million gallons of swap contracts that settle in future months.

As of December 31, 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 the following derivative instruments that settle in future months to match anticipated sales: 12.4 million gallons of swap contracts, 5.6 million gallons of call options, 7.7 million gallons of put options, and 94.1 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 December 31, 2014, had 29.6 million gallons of long future contracts, and 55.1 million gallons of short future contracts that settle in future months. To hedge its internal fuel usage for fiscal 2015, the Partnership as of December 31, 2014, had 2.9 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., Munich Re Trading LLC, 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 December 31, 2015, the aggregate cash posted as collateral in the normal course of business at counterparties was $2.6 million ($2.3 million recorded in prepaid expenses and other current assets and $0.3 million recorded in fair liability value of derivative instruments). Positions with counterparties who are also parties to our credit agreement are collateralized under that facility. As of December 31, 2015, $24.8 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 December 31, 2015
Commodity contracts	Fair asset and fair liability value of derivative instruments	$	51,220		$	6,670		$	44,550
Commodity contracts	Long-term derivative assets included in the other long-term liabilities balance		9,216			4,586			4,630

Commodity contract assets at December 31, 2015		$	60,436		$	11,256		$	49,180


Liability Derivatives at December 31, 2015
Commodity contracts	Fair liability and fair asset value of derivative instruments	$	(72,658	)	$	(6,265	)	$	(66,393	)
Commodity contracts	Cash collateral		320			320			—
Commodity contracts	Long-term derivative liabilities included in the other long-term liabilities balance		(9,041	)		(3,489	)		(5,552	)

Commodity contract liabilities at December 31, 2015		$	(81,379	)	$	(9,434	)	$	(71,945	)


Asset Derivatives at September 30, 2015
Commodity contracts	Fair asset and fair liability value of derivative instruments	$	26,628		$	930		$	25,698
Commodity contracts	Long-term derivative assets included in the other long-term liabilities balance		4,975			2,017			2,958

Commodity contract assets at September 30, 2015		$	31,603		$	2,947		$	28,656


Liability Derivatives at September 30, 2015
Commodity contracts	Fair liability and fair asset value of derivative instruments	$	(41,270	)	$	—		$	(41,270	)
Commodity contracts	Cash collateral		2,758			2,758			—
Commodity contracts	Long-term derivative liabilities included in the other long-term liabilities balance		(5,977	)		(2,038	)		(3,939	)

Commodity contract liabilities at September 30, 2015		$	(44,489	)	$	720		$	(45,209	)

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	$	6,670	$	(6,265	)	$	405		$	—	$	—	$	405
Long-term derivative assets included in deferred charges and other assets, net	$	5,162	$	(3,918	)	$	1,244		$	—	$	—	$	1,244
Fair liability value of derivative instruments		44,550		(66,073	)		(21,523	)		—		—		(21,523	)
Long-term derivative liabilities included in other long-term liabilities, net		4,054		(5,123	)		(1,069	)						(1,069	)

Total at December 31, 2015	$	60,436	$	(81,379	)	$	(20,943	)	$	—	$	—	$	(20,943	)


Fair asset value of derivative instruments	$	935	$	—		$	935		$	—	$	—	$	935
Fair liability value of derivative instruments		25,693		(38,512	)		(12,819	)		—		—		(12,819	)
Long-term derivative liabilities included in other long-term liabilities, net		4,975		(5,977	)		(1,002	)						(1,002	)

Total at September 30, 2015	$	31,603	$	(44,489	)	$	(12,886	)	$	—	$	—	$	(12,886	)


(In thousands)
The Effect of Derivative Instruments on the Statement of Operations
		Amount of (Gain) or Loss Recognized
Derivatives Not Designated as Hedging Instruments Under FASB ASC 815-10	Location of (Gain) or Loss Recognized in Income on Derivative	Three Months Ended December 31, 2015			Three Months Ended December 31, 2014

Commodity contracts	Cost of product (a)	$	(3,434	)	$	(6,805	)
Commodity contracts	Cost of installations and service (a)	$	226		$	486
Commodity contracts	Delivery and branch expenses (a)	$	315		$	474

Commodity contracts	(Increase) / decrease in the fair value of derivative instruments	$	5,536		$	8,290

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

5) Inventories

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


	December 31, 2015		September 30, 2015
Product	$	44,656	$	35,599
Parts and equipment		20,225		20,072

Total inventory	$	64,881	$	55,671

6) Property and Equipment

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


	December 31, 2015		September 30, 2015
Property and equipment	$	178,356	$	179,631
Less: accumulated depreciation		108,669		111,508

Property and equipment, net	$	69,687	$	68,123

7) Business Combination

During fiscal 2016, the Partnership acquired a motor fuel dealer and a propane dealer for an aggregate purchase price of approximately $7.6 million. The gross purchase price was allocated $3.8 million to intangible assets, $1.6 million to goodwill, $2.1 million to fixed assets and $0.1 million to working capital. 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, 2015	$	211,045
Fiscal year 2016 business combination		1,631

Balance as of December 31, 2015	$	212,676

Intangibles, net

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


	December 31, 2015						September 30, 2015
	Gross Carrying Amount		Accum. Amortization		Net		Gross Carrying Amount		Accum. Amortization		Net
Customer lists	$	325,594	$	239,868	$	85,726	$	322,027	$	236,438	$	85,589
Trade names and other intangibles		26,998		5,392		21,606		26,774		5,046		21,728

Total	$	352,592	$	245,260	$	107,332	$	348,801	$	241,484	$	107,317

Amortization expense for intangible assets was $3.8 million for the three months ended December 31, 2015, compared to $3.3 million for the three months ended December 31, 2014.

9) Long-Term Debt and Bank Facility Borrowings


The Partnership’s debt is as follows	December 31,				September 30,
(in thousands):	2015				2015
	Carrying Amount		Fair Value (a)		Carrying Amount		Fair Value (a)
Revolving Credit Facility Borrowings	$	—	$	—	$	—	$	—
Senior Secured Term Loan		100,000		100,000		100,000		100,000

Total debt	$	100,000	$	100,000	$	100,000	$	100,000

Total short-term portion of debt	$	10,000	$	10,000	$	10,000	$	10,000

Total long-term portion of debt	$	90,000	$	90,000	$	90,000	$	90,000

(a)	The face amount of the Partnership’s variable rate long-term debt approximates fair value.

On July 30, 2015, the Partnership entered into a third amended and restated asset based credit 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 credit facility 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 has a maturity date of July 30, 2020.

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 credit facility and the term loan is based on a margin over LIBOR or a base rate. At December 31, 2015, the effective interest rate on the term loan was approximately 3.57%.

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

The third amended and restated credit agreement requires the Partnership to meet certain financial covenants, including a fixed charge coverage ratio (as defined in the credit agreement) of not less than 1.1 as long as the $100 million Term Loan is outstanding or revolving credit facility 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.

At December 31, 2015, $100.0 million of the term loan was outstanding, no amount was outstanding under the revolving credit facility, $24.8 million of hedge positions were secured under the credit agreement, and $52.4 million of letters of credit were issued and outstanding. At September 30, 2015, $100.0 million of the term loan was outstanding, no amount was outstanding under the revolving credit facility, $15.3 million of hedge positions were secured under the credit agreement, and $54.8 million of letters of credit were issued and outstanding.

At December 31, 2015, availability was $184.2 million, and the Partnership was in compliance with the fixed charge coverage ratio and the senior secured leverage ratio. At September 30, 2015, availability was $176.0 million, and the Partnership was in compliance with the fixed charge coverage ratio and the senior secured leverage 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 months ended December 31, 2015, and 2014 are as follows:


	Three Months Ended December 31,
(in thousands)	2015		2014

Income before income taxes	$	21,475	$	26,913

Current tax expense	$	8,809	$	11,129
Deferred tax expense		608		230

Total tax expense	$	9,417	$	11,359

As of January 1, 2016, Star Acquisitions, Inc., a wholly-owned subsidiary of the Partnership, had an estimated Federal net operating loss carry forward (“NOLs”) of approximately $3.9 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.

Due to a change in a state tax law enacted in December 2015, the Partnership increased its valuation allowance by $0.5 million to a balance of $3.5 million at December 31, 2015.

At December 31, 2015, we did not have unrecognized income tax benefits.

Our continuing practice is to recognize interest and penalties related to income tax matters as a component of income tax expense. We file U.S. Federal income tax returns and various state and local returns. A number of years may elapse before an uncertain tax position is audited and finally resolved. For our Federal income tax returns we have four tax years subject to examination. In our major state tax jurisdictions of New York, Connecticut, Pennsylvania and New Jersey, we have four, four, four, and five tax years, respectively, that are subject to examination. While it is often difficult to predict the final outcome or the timing of resolution of any particular uncertain tax position, based on our assessment of many factors including past experience and interpretation of tax law, we believe that our provision for income taxes reflect the most probable outcome. This assessment relies on estimates and assumptions and may involve a series of complex judgments about future events.

11) Supplemental Disclosure of Cash Flow Information


	Three Months Ended December 31,
(in thousands)	2015		2014

Cash paid during the period for:
Income taxes, net	$	2,238	$	11,116
Interest	$	1,566	$	6,233

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

Non-cash operating activities:
Increase in interest expense—amortization of debt discount on 8.875% Senior Notes and amortization of deferred charges on senior secured term loan	$	71	$	30

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 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
Basic and Diluted Earnings Per Limited Partner:	December 31,
(in thousands, except per unit data)	2015		2014
Net income	$	12,058	$	15,554
Less General Partner’s interest in net income		68		88

Net income available to limited partners		11,990		15,466

Less dilutive impact of theoretical distribution of earnings under FASB ASC 260-10-45-60		1,231		1,930

Limited Partner’s interest in net income under FASB ASC 260-10-45-60	$	10,759	$	13,536


Per unit data:
Basic and diluted net income available to limited partners	$	0.21	$	0.27

Less dilutive impact of theoretical distribution of earnings under FASB ASC 260-10-45-60		0.02		0.03

Limited Partner’s interest in net income under FASB ASC 260-10-45-60	$	0.19	$	0.24


Weighted average number of Limited Partner units outstanding		57,281		57,294

14) Subsequent Events

Quarterly Distribution Declared

In January 2016, 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 first quarter of fiscal 2016, payable on February 5, 2016, to holders of record on February 1, 2016. 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.

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, 2012 through December 31, 2015, on a quarterly basis, is illustrated in the following chart (price per gallon):


	Fiscal 2016⁽¹⁾				Fiscal 2015⁽¹⁾				Fiscal 2014⁽¹⁾				Fiscal 2013 ⁽¹⁾				Fiscal 2012
Quarter Ended	Low		High		Low		High		Low		High		Low		High		Low		High
December 31	$	1.08	$	1.61	$	1.85	$	2.66	$	2.84	$	3.12	$	2.90	$	3.26	$	2.72	$	3.17
March 31		—		—		1.62		2.30		2.89		3.28		2.86		3.24		2.99		3.32
June 30		—		—		1.68		2.02		2.85		3.05		2.74		3.09		2.53		3.25
September 30		—		—		1.38		1.84		2.65		2.98		2.87		3.21		2.68		3.24

(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.

Impact of Warm Weather on Operating Results; Weather Hedge Contract

Weather conditions have a significant impact on the demand for home heating oil and propane because our customers depend on these products principally for heating purposes. Actual weather conditions can vary substantially from year to year, significantly affecting our financial performance. Over the last 30 years, the variation in temperatures based on heating degree days in our geographic areas of operations for the three month period ended December 31, have ranged from 32.7% warmer than normal to 19.8% colder than normal. The period from October 1, 2015 through December 31, 2015 was the warmest during the past 30 years. To partially mitigate the adverse effect of warm weather on our cash flows, we have used weather hedging contracts for a number of years. For the fiscal 2016 and 2017 heating seasons, we entered into a weather hedge contract under which we are entitled to receive a payment of $35,000 per heating degree-day shortfall, when the total number of heating degree-days in the period covered is less than approximately 92.5% of the ten year average (the “Payment Threshold”). The hedge covers the period from November 1 through March 31 taken as a whole, and has a maximum payout of $12.5 million. As of December 31, 2015, the Partnership recorded a

credit of $12.5 million under this contract that reduced delivery and branch expenses. The final credit (if any) for fiscal 2016 may be lower depending on the accumulation of actual heating degree-days recorded in the period January 1, 2016 through March 31, 2016. If the heating degree-days in this period approximate normal, the credit will be reduced to approximately $5.2 million. If temperatures in this period are colder than expected, then the additional heating degree-days could reduce the credit further, possibly even to zero. Temperatures recorded for January 2016, were slightly warmer than expected.

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.

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.

Income Taxes

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
2016	$	27,296	$	32,434
2017		24,354		23,852
2018		21,483		18,929
2019		19,674		16,129
2020		17,114		13,814
2021		12,871		12,212

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.

Customer gains and losses of home heating oil and propane customers


	Fiscal Year Ended
	2016							2015							2014
					Net							Net							Net
	Gross Customer				Gains /			Gross Customer				Gains /			Gross Customer				Gains /
	Gains		Losses		(Attrition)			Gains		Losses		(Attrition)			Gains		Losses		(Attrition)
First Quarter		22,800		24,200		(1,400	)		27,400		23,100		4,300			25,700		22,700		3,000
Second Quarter		—		—		0			16,000		18,200		(2,200	)		16,800		16,700		100
Third Quarter		—		—		0			7,400		14,000		(6,600	)		8,100		14,100		(6,000	)
Fourth Quarter		—		—		0			13,900		17,900		(4,000	)		17,500		18,700		(1,200	)

Total		22,800		24,200		(1,400	)		64,700		73,200		(8,500	)		68,100		72,200		(4,100	)

Customer gains and losses as a percentage of home heating oil and propane customer base


	Fiscal Year Ended
	2016									2015									2014
							Net									Net									Net
	Gross Customer						Gains /			Gross Customer						Gains /			Gross Customer						Gains /
	Gains			Losses			(Attrition)			Gains			Losses			(Attrition)			Gains			Losses			(Attrition)
First Quarter		5.0	%		5.3	%		(0.3	%)		6.2	%		5.2	%		1.0	%		6.1	%		5.3	%		0.8	%
Second Quarter		—			—			0.0	%		3.6	%		4.1	%		(0.5	%)		3.9	%		3.9	%		0.0	%
Third Quarter		—			—			0.0	%		1.7	%		3.1	%		(1.4	%)		1.9	%		3.3	%		(1.4	%)
Fourth Quarter		—			—			0.0	%		3.1	%		4.0	%		(0.9	%)		4.1	%		4.4	%		(0.3	%)

Total		5.0	%		5.3	%		(0.3	%)		14.6	%		16.4	%		(1.8	%)		16.0	%		16.9	%		(0.9	%)

Net account attrition for the first quarter of fiscal 2016 was 5,700 accounts greater than the first quarter of fiscal 2015. During the three months ended December 31, 2015, the Partnership lost 1,400 accounts (net), or 0.3%, of its home heating oil and propane customer base, compared to the three months ended December 31, 2014 in which the Partnership grew its customer base by 4,300 accounts (net) or 1.0%. For the three months ended December 31, 2015, our gross customer gains were 4,600 accounts less than the prior year’s comparable quarter and our gross customer losses for the first quarter of fiscal 2016 were 1,100 accounts higher than the three months ended December 31, 2015. The three months ended December 31, 2015 were 27.2% warmer than the three months ended December 31, 2014 and 32.7% warmer than normal. In addition, the wholesale cost of product declined by $0.9150 per gallon, or 39.6%, year-over-year. We believe that our gross customer gains and ability to attract new accounts was impacted by the extremely warm weather as potential new accounts did not see a need for the level of service that we can provide. The precipitous drop in the wholesale cost of product also enabled competitors to lower their product offerings to levels that are not currently economically attractive for us. The increase in gross customer losses was largely due to an increase in price losses.

During the three months ended December 31, 2015, we lost 0.5% of our home heating oil accounts to natural gas conversions versus 0.6% during the first quarter of fiscal 2015 and 0.7% for the first quarter of fiscal 2014. Conversions to natural gas may continue as natural gas 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 December 31, 2015

Compared to the Three Months Ended December 31, 2014

Volume

For the three months ended December 31, 2015, retail volume of home heating oil and propane decreased by 27.4 million gallons, or 25.5%, to 80.1 million gallons, compared to 107.5 million gallons for the three months ended December 31, 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 three months ended December 31, 2015 were 27.2% warmer than the three months ended December 31, 2014 and 32.7% warmer than normal, as reported by NOAA. For the twelve months ended December 31, 2015, net customer attrition for the base business was 3.2%. The impact of fuel conservation, along with any period-to-period differences in delivery scheduling, the timing of accounts added or lost during the fiscal years, equipment efficiency and other volume variances not otherwise described, are included in the chart below under the heading “Other.” An analysis of the change in the retail volume of home heating oil and propane, which is based on management’s estimates, sampling and other mathematical calculations and certain assumptions, is found below:


(in millions of gallons)	Heating Oil and Propane
Volume - Three months ended December 31, 2014		107.5
Acquisitions		4.3
Impact of warmer temperatures		(29.6	)
Net customer attrition		(3.1	)
Other		1.0

Change		(27.4	)


Volume - Three months ended December 31, 2015		80.1

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 December 31, 2015 compared to the three months ended December 31, 2014:


	Three Months Ended
Customers	December 31, 2015			December 31, 2014
Residential Variable		39.5	%		38.8	%
Residential Price-Protected		47.5	%		47.1	%
Commercial/Industrial		13.0	%		14.1	%

Total		100.0	%		100.0	%

Over the last several years, 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. The customer mix from recent acquisitions resulted in a slight percentage increase in residential variable volume sold and a slight decrease in the percentage of commercial volume sold.

Volume of other petroleum products increased by 1.5 million gallons, or 5.6%, to 27.3 million gallons for the three months ended December 31, 2015, compared to 25.8 million gallons for the three months ended December 31, 2014 as a decline in the base business of 2.0 million gallons, or 8.0%, was more than offset by acquisitions which contributed 3.5 million gallons. The decline in the base business was largely due to a weather driven decline in low margin wholesale sales.

Product Sales

For the three months ended December 31, 2015, product sales decreased $182.1 million, or 41.9%, to $252.9 million, compared to $435.0 million for the three months ended December 31, 2014, due to a decline in wholesale product costs of $0.9150 per gallon, or 39.6%, and a decline in total volume of 19.5%, which was slightly offset by higher per gallon gross profit margins.

Installations and Services

For the three months ended December 31, 2015, installation and service sales increased $1.9 million, or 3.0%, to $66.1 million, compared to $64.2 million for the three months ended December 31, 2014, due primarily to acquisitions.

Cost of Product

For the three months ended December 31, 2015, cost of product decreased $159.1 million, or 51.5%, to $150.1 million, compared to $309.2 million for the three months ended December 31, 2014, due largely to a $0.9150 per gallon, or 39.6%, decline in wholesale product cost and a decline in total volume of 19.5%.

Gross Profit—Product

The table below calculates the Partnership’s per gallon margins and reconciles product gross profit for home heating oil and propane and other petroleum products. We believe the change in home heating oil and propane margins should be evaluated before the effects of increases or decreases in the fair value of derivative instruments, as we believe that realized per gallon margins should not include the impact of non-cash changes in the market value of hedges before the settlement of the underlying transaction. On that basis, home heating oil and propane margins for the three months ended December 31, 2015 increased by $0.0811 per gallon, or 7.4%, to $1.1817 per gallon, from $1.1006 per gallon during the three months ended December 31, 2014. The Partnership was able to expand its per gallon margins due to the decline in per gallon wholesale product costs of $0.9150. Over the last 24 months the cost of home heating oil has declined by $2.20 per gallon. Going forward, the Partnership cannot guarantee that the per gallon margins achieved during the three months ended December 31, 2015 are sustainable. Product sales and cost of product include home heating oil, propane, other petroleum products and liquidated damages billings.


	Three Months Ended
	December 31, 2015				December 31, 2014
Home Heating Oil and Propane	Amount (in millions)		Per Gallon		Amount (in millions)		Per Gallon
Volume		80.1				107.5

Sales	$	206.3	$	2.5772	$	366.6	$	3.4111
Cost	$	111.7	$	1.3955	$	248.3	$	2.3105


Gross Profit	$	94.6	$	1.1817	$	118.3	$	1.1006


Other Petroleum Products	Amount (in millions)		Per Gallon		Amount (in millions)		Per Gallon
Volume		27.3				25.9

Sales	$	46.6	$	1.7072	$	68.4	$	2.6457
Cost	$	38.4	$	1.4055	$	60.9	$	2.3568


Gross Profit	$	8.2	$	0.3017	$	7.5	$	0.2889


Total Product	Amount (in millions)				Amount (in millions)
Sales	$	253.0			$	435.0
Cost	$	150.1			$	309.2


Gross Profit	$	102.8			$	125.8

For the three months ended December 31, 2015, total product gross profit was $102.8 million, $22.9 million less than for the three months ended December 31, 2014, as the impact of higher home heating oil and propane margins was more than offset by a decline in home heating oil and propane volume.

Cost of Installations and Services

Total installation costs for the three months ended December 31, 2015 increased by $1.0 million, or 4.8%, to $22.2 million, compared to $21.2 million in installation costs for the three months ended December 31, 2014 due to acquisitions and some growth in the base business. Installation costs as a percentage of installation sales for the three months ended December 31, 2015 and the three months ended December 31, 2014 were 81.8% and 81.9%, respectively.

Service expenses increased to $40.7 million for the three months ended December 31, 2015, or 104.5% of service sales, versus $39.5 million, or 103.1% of service sales for the three months ended December 31, 2014 largely due to acquisitions. We experienced a combined gross profit from service and installation of $3.2 million for the three months ended December 31, 2015 compared to a combined gross profit of $3.5 million for the three months ended December 31, 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 December 31, 2015, the change in the fair value of derivative instruments resulted in a $5.5 million charge as a decrease in the market value for unexpired hedges (a $9.2 million charge) was reduced by a $3.7 million credit due to the expiration of certain hedged positions.

During the three months ended December 31, 2014, the change in the fair value of derivative instruments resulted in an $8.3 million charge due to the expiration of certain hedged positions (a $4.2 million credit) and a decrease in the market value of unexpired hedges (a $12.5 million charge). The decrease in market value was largely due to the decline in the price of home heating oil.

Delivery and Branch Expenses

For the three months ended December 31, 2015, delivery and branch expenses decreased $14.6 million, or 18.6%, to $64.2 million, compared to $78.8 million for the three months ended December 31, 2014, as an acquisition related increase of $3.0 million was more than offset by lower delivery and branch expenses of $5.1 million related to the decline in volume and a $12.5 million credit recorded under the Partnership’s weather hedge contract. The final credit (if any) for fiscal 2016 may be lower depending on the accumulation of actual heating degree-days recorded in the period January 1, 2016 through March 31, 2016. If the heating degree-days in this period approximate normal, the credit will be reduced to approximately $5.2 million. If temperatures in this period are colder than expected, then the additional heating degree-days could reduce the credit further, possibly even to zero. Temperatures recorded for January 2016, were slightly warmer than expected.

Depreciation and Amortization

For the three months ended December 31, 2015, depreciation and amortization expense increased by $0.6 million, or 9.9 %, to $6.8 million, compared to $6.2 million for the three months ended December 31, 2014 due to acquisitions.

General and Administrative Expenses

For the three months ended December 31, 2015, general and administrative expenses increased $0.3 million, to $6.4 million, from $6.1 million for the three months ended December 31, 2014, primarily due to higher staffing and benefits costs and an increase in the Partnership’s frozen pension plan expense, partially offset by a reduction in profit sharing expense.

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

Finance Charge Income

For the three months ended December 31, 2015, finance charge income decreased by $0.3 million, or 37.0%, to $0.5 million compared to $0.8 million for the three months ended December 31, 2014. The decline in the wholesale cost of product and the decline in volume led to lower product sales and thus a decline in accounts receivable balances subject to a finance charge.

Interest Expense, Net

For the three months ended December 31, 2015, interest expense decreased $1.6 million, or 46.3%, to $1.9 million compared to $3.5 million for the three months ended December 31, 2014. In September 2015, the Partnership redeemed its $125.0 million principal amount of 8.875% Senior Notes outstanding due 2017 with proceeds from a new, five year $100.0 million bank term-loan and cash. This refinancing drove the reduction in interest expense due to lower variable rates and lower principle outstanding.

Amortization of Debt Issuance Costs

For the three months ended December 31, 2015, amortization of debt issuance costs was relatively unchanged at $0.3 million compared to the three months ended December 31, 2014.

Income Tax Expense

For the three months ended December 31, 2015, income tax expense decreased by $2.0 million to $9.4 million, from $11.4 million for the three months ended December 31, 2014, primarily due to a decrease in income before income taxes of $5.4 million. The Partnership’s effective income tax rate was 43.9% for the three months ended December 31, 2015 compared to 42.2% for the three months ended December 31, 2014, an increase of 1.7%. This increase in the effective income tax rate was driven by a $0.5 million increase in the valuation allowance due to a change in a state tax law enacted in December 2015.

Net Income

For the three months ended December 31, 2015, net income decreased $3.5 million, or 22.5%, to $12.1 million, from $15.6 million for the three months ended December 31, 2014, due to a decrease in pretax profit of $5.4 million which was reduced by a decline in income tax expense of $2.0 million.

Adjusted EBITDA

For the three months ended December 31, 2015, Adjusted EBITDA decreased by $9.3 million, or 20.5%, to $35.9 million as the impact of higher home heating oil and propane per gallon margins, lower operating expenses in the base business, and the $12.5 million credit recorded under the weather insurance contract were more than offset by the impact on Adjusted EBITDA of the decline in volume attributable to the 27.2% warmer weather. The final credit (if any) for fiscal 2016 may be lower than the $12.5 million recorded depending on the actual heating degree-days recorded in the period January 1, 2016 through March 31, 2016. If the heating degree-days in this period approximate normal, the credit will be reduced to approximately $5.2 million. If temperatures in this period are colder than expected, then the additional heating degree-days could reduce the credit further, possibly even to zero. Temperatures recorded for January 2016, were slightly warmer than expected.

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

EBITDA and Adjusted EBITDA are calculated as follows:


	Three Months Ended December 31,
(in thousands)	2015			2014

Net income	$	12,058		$	15,554
Plus:
Income tax expense		9,417			11,359
Amortization of debt issuance cost		312			400
Interest expense, net		1,859			3,460
Depreciation and amortization		6,766			6,158

EBITDA (a)		30,412			36,931

(Increase) / decrease in the fair value of derivative instruments		5,536			8,290

Adjusted EBITDA (a)		35,948			45,221

Add / (subtract)
Income tax expense		(9,417	)		(11,359	)
Interest expense, net		(1,859	)		(3,460	)
Provision for losses on accounts receivable		(636	)		236
Increase in accounts receivables		(22,263	)		(58,241	)
Increase in inventories		(9,064	)		(8,633	)
Increase (decrease) in customer credit balances		10,427			(5,862	)
Change in deferred taxes		609			230
Increase in weather hedge contract receivable		(12,500	)		—
Change in other operating assets and liabilities		11,954			28,448

Net cash provided by (used in) operating activities	$	3,199		$	(13,420	)


Net cash used in investing activities	$	(10,798	)	$	(1,684	)


Net cash used in financing activities	$	(6,019	)	$	(5,789	)

(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, multiemployer pension plan withdrawal charge, 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 EBITDA and Adjusted EBITDA both have limitations as analytical tools and so should not be viewed in isolation and should be viewed in conjunction with measurements that are computed in accordance with GAAP. Some of the limitations of EBITDA and Adjusted EBITDA are:

•

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

•

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

•

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

•

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

•

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

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 three months ended December 31, 2015, cash provided by operating activities increased by $16.6 million to $3.2 million, when compared to $13.4 million of cash used in operating activities during the three months ended December 31, 2014, as a $18.7 million decrease in cash generated from operations and the timing of cash used to fund accounts payable of $23.3 million was more than offset by a favorable change in cash relating to accounts receivable of $52.3 million (including customer credit balances), and a favorable change in other assets of $6.7 million primarily due to the timing of tax and other payments. The impact of significantly warmer weather and the continuing decline in product costs drove the favorable change in accounts receivable. The warm temperatures experienced in the three months ended December 31, 2015 resulted in a reduction in product purchases and lower accounts payable levels.

Investing Activities

Our capital expenditures for the three months ended December 31, 2015 totaled $3.2 million, as we invested in computer hardware and software ($1.0 million), refurbished certain physical plants ($0.2 million), expanded our propane operations ($0.9 million) and made additions to our fleet and other equipment ($1.1 million). We also completed two acquisitions for $7.6 million and allocated $3.8 million of the gross purchase price to intangible assets, $1.6 million to goodwill, $2.1 million to fixed assets and $0.1 million to working capital.

Our capital expenditures for the three months ended December 31, 2014 totaled $1.8 million, as we invested in computer hardware and software ($0.4 million), refurbished certain physical plants ($0.4 million), expanded our propane operations ($0.6 million) and made additions to our fleet and other equipment ($0.4 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 three months ended December 31, 2015, we paid distributions of $5.4 million to our Common Unit holders and $0.1 million to our General Partner unit holders (including $0.09 million of incentive distributions as provided in our Partnership Agreement).

During the three months ended December 31, 2014, we paid distributions of $5.0 million to our Common Unit holders, $0.09 million to our General Partner unit holders (including $0.05 million of incentive distributions as provided in our Partnership Agreement) and repurchased 0.12 million units for $0.7 million in connection with our unit repurchase plan.

FINANCING AND SOURCES OF LIQUIDITY

Liquidity and Capital Resources Comparatives

Our primary uses of liquidity are to provide funds for our working capital, capital expenditures, distributions on our units, acquisitions and unit repurchases. Our ability to provide funds for such uses depends on our future performance, which will be subject to prevailing economic, financial, business and weather conditions, the ability to pass on the full impact of high product costs to customers, the effects of high net customer attrition, conservation and other factors. Capital requirements, at least in the near term, are expected to be provided by cash flows from operating activities, cash on hand as of December 31, 2015 ($86.9 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 December 31, 2015, we had no borrowings under our revolving credit facility and $52.4 million in letters of credit were outstanding, primarily for current and future insurance reserves. Our ability to borrow was reduced by $24.5 million to secure hedges with the bank group.

Under the terms of the third amended and restated credit agreement, 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. We must also maintain a senior secured leverage ratio that 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. As of December 31, 2015, Availability, as defined in the credit agreement, was $184.2 million, and we were in compliance with the fixed charge coverage ratio and senior secured leverage ratio.

Maintenance capital expenditures for the remainder of fiscal 2016 are estimated to be approximately $6.3 million, excluding the capital requirements for leased fleet. In addition, we plan to invest an additional $2.0 million in our propane operations. Distributions for the balance of fiscal 2016, at the current quarterly level of $0.095 per unit, would result in an aggregate of approximately $16.3 million to Common Unit holders, $0.3 million to our general partner (including $0.26 million of incentive distribution as provided for in our Partnership Agreement) and $0.26 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. Under the terms of our credit facility, our term loan is repayable in quarterly payments of $2.5 million, and depending on our fiscal 2016 results, we may be required to make an additional payment. (See Note 9—Long-Term Debt and Bank Facility Borrowings) 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, 2015, 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, Simplifying the Presentation of Debt Issuance Costs

•

ASU No. 2015-11, Simplifying the Measurement of Inventory

•

ASU No. 2015-16, Simplifying the Accounting for Measurement-Period Adjustments

•

ASU 2015-17, Income Taxes - Balance Sheet Classification of Deferred Taxes

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

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

At December 31, 2015, we had outstanding borrowings totaling $100.0 million, which are subject to variable interest rates under our credit agreement. In the event that interest rates associated with this facility were to increase 100 basis points, the after tax impact on annual future cash flows would be a decrease of $0.5 million.

We regularly 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 and vehicle fuels. The value of market sensitive derivative instruments is subject to change as a result of movements in market prices. Sensitivity analysis is a technique used to evaluate the impact of hypothetical market value changes. Based on a hypothetical ten percent increase in the cost of product at December 31, 2015, the potential impact on our hedging activity would be to increase the fair market value of these outstanding derivatives by $0.1 million to a negative fair market value of $(20.8) million; and conversely a hypothetical ten percent decrease in the cost of product would increase the fair market value of these outstanding derivatives by $3.3 million to a negative fair market value of $(17.6) 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 December 31, 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 December 31, 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

On August 4, 2015, the Partnership completed the acquisition of a heating oil and motor fuel dealer. The Partnership is in the early stages of integrating the heating and motor fuel dealer. The Partnership is analyzing, evaluating and, where necessary, will implement changes in controls and procedures relating to the dealer’s business as integration proceeds. As a result, this process may result in additions or changes to our internal control over financial reporting.

Otherwise, there were no changes in our internal control over financial reporting during the Partnership’s most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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 December 31, 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 2015 Form 10-K. We may disclose changes to such factors or disclose additional factors from time to time in our future filings with the SEC.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

Not applicable.

Item 6.

Exhibits

(a)	Exhibits Included Within:


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

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

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

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

101		The following materials from the Star Gas Partners, L.P. Quarterly Report on Form 10-Q for the quarter ended December 31, 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 Richard F. Ambury	Executive Vice President, Chief Financial Officer, Treasurer and Secretary Kestrel Heat LLC (Principal Financial Officer)	February 3, 2016


Signature	Title	Date

/s/ Richard G. Oakley Richard G. Oakley	Senior Vice President - Controller Kestrel Heat LLC (Principal Accounting Officer)	February 3, 2016

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company