10-K 1 d593270d10k.htm FORM 10-K

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-K

(Mark One)

x | ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

| For the fiscal year ended September 30, 2013

OR

¨ | 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 registrant as specified in its charter)

Delaware |  | 06-1437793
(State or other jurisdiction of incorporation or organization) |  | (I.R.S. Employer Identification No.)
2187 Atlantic Street, Stamford, Connecticut |  | 06902
(Address of principal executive office) |  | (Zip Code)

(203) 328-7310

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class |  | Name of each exchange on which registered
Common Units |  | New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x

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 (§232.405 of this chapter) 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” and “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Act (check one).

Large accelerated filer ¨ Accelerated filer x Non-accelerated filer ¨ Smaller reporting company ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

The aggregate market value of the registrant’s common units held by non-affiliates on March 31, 2013 was approximately $270,937,000. As of November 30, 2013, the registrant had 57,467,744 common units outstanding.

Documents Incorporated by Reference: None

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STAR GAS PARTNERS, L.P.

2013 FORM 10-K ANNUAL REPORT

TABLE OF CONTENTS

|  |  |  | Page |
|  | PART I |  |  |  |
Item 1. |  | Business |  |  | 3 |
Item 1A. |  | Risk Factors |  |  | 11 |
Item 1B. |  | Unresolved Staff Comments |  |  | 22 |
Item 2. |  | Properties |  |  | 22 |
Item 3. |  | Legal Proceedings—Litigation |  |  | 22 |
Item 4. |  | Mine Safety Disclosures |  |  | 22 |
|  | PART II |  |  |  |
Item 5. |  | Market for the Registrant’s Units and Related Matters |  |  | 22 |
Item 6. |  | Selected Historical Financial and Operating Data |  |  | 25 |
Item 7. |  | Management’s Discussion and Analysis of Financial Condition and Results of Operations |  |  | 27 |
Item 7A. |  | Quantitative and Qualitative Disclosures about Market Risk |  |  | 47 |
Item 8. |  | Financial Statements and Supplementary Data |  |  | 47 |
Item 9. |  | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |  |  | 47 |
Item 9A. |  | Controls and Procedures |  |  | 47 |
Item 9B. |  | Other Information |  |  | 48 |
|  | PART III |  |  |  |
Item 10. |  | Directors, Executive Officers and Corporate Governance |  |  | 48 |
Item 11. |  | Executive Compensation |  |  | 52 |
Item 12. |  | Security Ownership of Certain Beneficial Owners and Management |  |  | 62 |
Item 13. |  | Certain Relationships and Related Transactions |  |  | 63 |
Item 14. |  | Principal Accounting Fees and Services |  |  | 64 |
|  | PART IV |  |  |  |
Item 15. |  | Exhibits and Financial Statement Schedules |  |  | 65 |

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PART I

Statement Regarding Forward-Looking Disclosure

This Annual Report on Form 10-K 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.

ITEM 1. | BUSINESS

Structure

Star Gas Partners, L.P. (“Star Gas Partners,” the “Partnership,” “we,” “us,” or “our”) is a home heating oil and propane distributor and services provider with one reportable operating segment that principally provides services to residential and commercial customers to heat homes and buildings. Star Gas Partners is a Delaware limited partnership, which at November 30, 2013, had outstanding 57.5 million common partner units (NYSE: “SGU”) representing a 99.44% limited partner interest in Star Gas Partners, and 0.3 million general partner units, representing a 0.56% general partner interest in Star Gas Partners. Our general partner is Kestrel Heat, LLC, a Delaware limited liability company (“Kestrel Heat” or the “general partner”).

The following chart depicts the ownership of the partnership as of November 30, 2013:

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The Partnership is organized as follows:

| • |  | Our general partner is Kestrel Heat. The Board of Directors of Kestrel Heat is appointed by its sole member, Kestrel Energy Partners, LLC, a Delaware limited liability company (“Kestrel”).

| • |  | Our operations are conducted through Petro Holdings, Inc. (a Minnesota corporation that is our indirect wholly owned subsidiary) and its subsidiaries, all of which are corporations subject to Federal and state income taxes. At December 31, 2012, our Federal Net Operating Loss carryforwards (“NOLs”) were $10.6 million, subject to annual limitations on the amount of losses that can be used of between $1.0 million and $2.2 million.

| • |  | Star Gas Finance Company is our 100% owned subsidiary. Star Gas Finance Company serves as the co-issuer, jointly and severally with us, of our $125.0 million 8.875% Senior Notes (excluding discounts), which are due in December 2017, that we sometimes refer to in this Report as the notes or the senior notes. We are dependent on distributions, including inter-company dividends and interest payments, from our subsidiaries to service our debt obligations. The distributions from our subsidiaries are not guaranteed and are subject to certain loan restrictions. Star Gas Finance Company has nominal assets and conducts no business operations. (See Note 11 of the Notes to the Consolidated Financial Statements - Long-Term Debt and Bank Facility Borrowings)

We file annual, quarterly, current and other reports and information with the Securities and Exchange Commission, or SEC. These filings can be viewed and downloaded from the Internet at the SEC’s website at www.sec.gov. In addition, these SEC filings are available at no cost as soon as reasonably practicable after the filing thereof on our website at www.star-gas.com/sec.cfm. These reports are also available to be read and copied at the SEC’s public reference room located at Judiciary Plaza, 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330. You may also obtain copies of these filings and other information at the offices of the New York Stock Exchange located at 11 Wall Street, New York, New York 10005. Please note that any Internet addresses provided in this Annual Report on Form 10-K are for informational purposes only and are not intended to be hyperlinks. Accordingly, no information found and/or provided at such Internet addresses is intended or deemed to be incorporated by reference herein.

Partnership Structure

The following chart summarizes our partnership structure as of September 30, 2013. Other than Star Gas Partners, L.P. all other entities in this structure are taxable as corporations for Federal and state income tax purposes.

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Business Overview

As of September 30, 2013, we sold home heating oil and propane to approximately 404,000 full service residential and commercial customers. We believe we are the largest retail distributor of residential home heating oil in the United States, based upon sales volume. We also sell home heating oil, gasoline and diesel fuel to approximately 54,000 customers on a delivery only basis. We install, maintain, and repair heating and air conditioning equipment for our customers and provide ancillary home services, including home security and plumbing, to approximately 15,700 customers. During fiscal 2013, total sales were comprised of approximately 75% from sales of home heating oil and propane; 13% from the installation and repair of heating and air conditioning equipment and ancillary services; and 12% from the sale of other petroleum products. We provide home heating equipment repair service 24 hours a day, seven days a week, 52 weeks a year. These services are an integral part of our business and are intended to maximize customer satisfaction and loyalty.

We conduct our business through an operating subsidiary, Petro Holdings, Inc., and its subsidiaries, utilizing over 30 local brand names such as Petro Heating & Air Conditioning Services and Meenan Oil. We believe that the Petro, Meenan and other trademarks and service marks are an important part of our ability to attract new customers and to effectively maintain and service our customer base.

We offer several pricing alternatives to our residential home heating oil customers, including a variable price (market based) option and a price-protected option, the latter of which either sets the maximum price or a fixed price that a customer will pay. Approximately 96% of our full service residential and commercial home heating oil and propane customers automatically receive deliveries based on prevailing weather conditions. In addition, we offer a “smart pay” budget payment plan in which homeowners’ estimated annual oil and propane deliveries and service billings are paid for in a series of equal monthly installments. We utilize derivative instruments in order to hedge a substantial majority of the home heating oil volume we expect to sell to price-protected customers that have renewed their price-protected plans, mitigating our exposure to changing commodity prices. We also use derivative instruments as a hedge against our home heating oil physical inventory and home heating oil priced purchase commitments. Our size gives us the ability to realize economies of scale and the ability to provide consistent, strong customer service.

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Currently, we have heating oil and/or propane customers in the following states, regions and counties:

Maine York New Hampshire Hillsborough County Merrimack Rockingham Strafford Vermont Bennington Rutland Massachusetts Barnstable Berkshire Bristol Essex Middlesex Norfolk Plymouth Suffolk Worcester Rhode Island Bristol Kent Newport Providence Washington Connecticut Fairfield Hartford Litchfield Middlesex New Haven New London Tolland Windham |  | New York Albany Bronx Columbia Dutchess Essex Franklin Fulton Greene Hamilton Kings Montgomery Nassau New York Onondaga Orange Putnam Queens Rensselaer Richmond Rockland Saratoga Schenectady Schoharie Suffolk Sullivan Ulster Warren Washington Westchester |  | New Jersey Bergen Burlington Camden Essex Gloucester Hudson Hunterdon Mercer Middlesex Monmouth Morris Ocean Passaic Salem Somerset Sussex Union Warren Pennsylvania Berks Bucks Chester Cumberland Dauphin Delaware Lancaster Lebanon Lehigh Monroe Montgomery Northampton Perry Philadelphia Pike York |  | Maryland Anne Arundel Baltimore Calvert Carroll Cecil Charles Frederick Harford Howard Montgomery North Calvert Prince George’s Washington, D.C. District of Columbia Virginia Arlington Fairfax Fauquier Loudoun Prince William Stafford North Carolina Union County South Carolina Bamberg Calhoun Dorchester Lexington Orangeburg

Industry Characteristics

Home heating oil is primarily used as a source of fuel to heat residences and businesses in the Northeast and Mid-Atlantic regions. According to the U.S. Department of Energy—Energy Information Administration, 2009 Residential Energy Consumption Survey (the latest survey published), these regions account for 83% (5.7 million of 6.9 million) of the households in the United States where heating oil is the main space-heating fuel and 28% (5.7 million of 20.8 million) of the homes in these regions use home heating oil as their main space-heating fuel. In recent years, as the price of home heating oil increased, customers have tended to increase their conservation efforts, which has decreased their consumption of home heating oil.

The retail home heating oil industry is mature, with total market demand expected to decline in the foreseeable future due to conversions to natural gas. We believe that conversions to natural gas have increased and may continue to do so as natural gas has become significantly less expensive than home heating oil on an equivalent BTU basis. Our customer losses to natural gas conversions for fiscal years 2013, 2012 and 2011 were 2.4%, 2.0% and 1.5% respectively. Therefore, our ability to maintain our business or grow within the industry is dependent on the acquisition of other retail distributors as well as the success of our marketing programs. Conversions to natural gas are increasing and we believe this may continue as natural gas has become significantly less expensive than home heating oil on an equivalent BTU basis. In addition, the states of New York, Connecticut and Pennsylvania are seeking to encourage homeowners to expand the use of natural gas as a heating fuel through legislation and regulatory efforts.

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Propane is a by-product of natural gas processing and petroleum refining. Propane use falls into three broad categories: residential and commercial applications; industrial applications; and agricultural uses. In the residential and commercial markets, propane is used primarily for space heating, water heating, clothes drying and cooking. Industrial customers use propane generally as a motor fuel to power over-the-road vehicles, forklifts and stationary engines, to fire furnaces, as a cutting gas and in other process applications. In the agricultural market, propane is primarily used for tobacco curing, crop drying, poultry breeding and weed control.

It is common practice in our business to price products to customers based on a per gallon margin over wholesale costs. As a result, we believe distributors such as ourselves generally seek to maintain their per gallon margins by passing wholesale price increases through to customers, thus insulating their margins from the volatility in wholesale prices. However, distributors may be unable or unwilling to pass the entire product cost increases through to customers. In these cases, significant decreases in per gallon margins may result. The timing of cost pass-throughs can also significantly affect margins. The retail home heating oil industry is highly fragmented, characterized by a large number of relatively small, independently owned and operated local distributors. Some dealers provide full service, as we do, and others offer delivery only on a cash-on-delivery basis, which we also do to a significantly lesser extent. The industry is complex and costly due to regulations, working capital requirements and the cost to hedge for price-protected customers.

Business Strategy

Our business strategy is to increase operating profits and cash flow by conservatively managing our operations and growing and retaining our customer base as a retail distributor of home heating oil and propane and provider of ancillary products and services. The key elements of this strategy include the following:

Deliver superior customer service. We are completely focused on providing the best customer service in our regions, with the aim of maximizing customer satisfaction and retention. To engage our employees and enhance their ability to provide superior customer service and reduce gross customer losses, we require all employees to go through customer service training—supplemented by ongoing monitoring and guidance from management.

Broaden products and services. We sell related and complementary products and services, such as air conditioning systems, plumbing services, generators and home security systems, in order to leverage our organizational structure and improve our sales penetration within our existing customer base. We strive to increase the quality and breadth of our service offerings and believe that these efforts will further enhance our position with existing and potential customers, allowing us to maintain or improve customer retention.

Pursue select acquisitions. Our senior management team has developed expertise in identifying acquisition opportunities and integrating acquired customers into our operations. Through our acquisitions, we have been able to increase our presence in some of our existing geographic markets and selectively expand into new markets. Our acquisition strategy has enabled us to achieve our current market position and offers us the opportunity to achieve operating efficiencies and economies of scale.

Continue to focus on operating efficiencies. We constantly work to reduce operating costs and streamline our operations through the elimination of redundant systems and appropriate reductions in overhead.

Seasonality

Our fiscal year ends on September 30. All references to quarters and years respectively in this document are to fiscal quarters and years unless otherwise noted. The seasonal nature of our business results 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 of each fiscal year, the peak heating season. As a result, we generally realize net income in our first and second fiscal quarters and net losses during our third and fourth fiscal quarters and we expect that the negative impact of seasonality on our third and fourth fiscal quarter operating results will continue. In addition, sales volume typically fluctuates from year to year in response to variations in weather, wholesale energy prices and other factors.

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Competition

Most of our operating locations compete with numerous distributors, primarily on the basis of price, reliability of service and response to customer needs. Each such location operates in its own competitive environment.

We compete with distributors offering a broad range of services and prices, from full-service distributors, such as ourselves, to those offering delivery only. As do many companies in our business, we provide home heating and propane equipment repair service on a 24-hour-a-day, seven-day-a-week, 52 weeks a year basis. We believe that this level of service tends to help build customer loyalty. In some instances homeowners have formed buying cooperatives that seek a lower price than individual customers are otherwise able to obtain. Our business competes for retail customers with suppliers of alternative energy products, principally natural gas, propane (in the case of our home heating oil operations) and electricity.

Customer Attrition

We measure net customer attrition for our full service residential and commercial home heating oil and propane customers. Since October 1, 2010, we have included propane customers in this calculation as several of our acquisitions since such date have included propane operations. 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 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 conversions to natural gas. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Customer Attrition.)

Customers and Pricing

Our full service home heating oil customer base is comprised of 95% residential customers and 5% commercial customers. Our residential customer receives on average 150 gallons per delivery and our commercial accounts receive on average 310 gallons per delivery. Typically, we make four to six deliveries per customer per year. Currently, 96% of our full service residential and commercial home heating oil customers have their deliveries scheduled automatically and 4% of our home heating oil customer base call from time to time to schedule a delivery. Automatic deliveries are scheduled based on each customer’s historical consumption pattern and prevailing weather conditions. Our practice is to bill customers promptly after delivery. We also offer a balanced payment plan in which a customer’s estimated annual oil purchases and service contract fees are paid for in a series of equal monthly payments. Approximately 38% of our residential home heating oil customers have selected this billing option.

We offer several pricing alternatives to our residential home heating oil customers. Our variable pricing program allows the price to float with the home heating oil market and other factors. In addition, we offer price protected programs, which establish either a ceiling or a fixed price per gallon that the customer would pay over a defined period. The following chart depicts the percentage of the pricing plans selected by our residential home heating oil customers as of the end of the fiscal year.

|  | September 30, |
|  | 2013 |  |  | 2012 |  |  | 2011 |  |  | 2010 |  |  | 2009 |
Variable |  |  | 53.1 | % |  |  | 54.7 | % |  |  | 54.9 | % |  |  | 55.8 | % |  |  | 52.3 | %
Ceiling |  |  | 42.3 | % |  |  | 40.5 | % |  |  | 41.5 | % |  |  | 41.8 | % |  |  | 44.6 | %
Fixed |  |  | 4.6 | % |  |  | 4.8 | % |  |  | 3.6 | % |  |  | 2.4 | % |  |  | 3.1 | %
|  |  | 100.0 | % |  |  | 100.0 | % |  |  | 100.0 | % |  |  | 100.0 | % |  |  | 100.0 | %

Sales to residential customers ordinarily generate higher per gallon margins than sales to commercial customers. Due to greater price sensitivity and hedging costs of residential price-protected customers, the per gallon margins realized from price protected customers generally are less than from variable priced residential customers.

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Derivatives

We use derivative instruments in order to mitigate our exposure to market risk associated with the purchase of home heating oil for our price-protected customers, physical inventory on hand, inventory in transit and priced purchase commitments. Currently, the Partnership’s derivative instruments are with the following counterparties: Bank of America, N.A., Bank of Montreal, Cargill, Inc., Citibank, N.A., JPMorgan Chase Bank, N.A., Key Bank, N.A., Regions Financial Corporation, Societe Generale, and Wells Fargo Bank, N.A.

The Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“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 during the holding period 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. Depending on the risk being hedged, realized gains and losses are recorded in cost of product, cost of installations and service, or delivery and branch expenses.

Suppliers and Supply Arrangements

We purchase our product for delivery in either barge, pipeline or truckload quantities, and as of September 30, 2013 had contracts with approximately 70 third-party terminals for the right to temporarily store petroleum products and propane at their facilities. Home heating oil and propane purchases are made under supply contracts or on the spot market. We have entered into market price based contracts for approximately 81% of our expected retail home heating oil and propane requirements for the fiscal 2014 heating season. During fiscal 2013, Global Companies LLC and JPMorgan Ventures Energy Corporation provided approximately 19% and 11%, respectively, of our petroleum product purchases. No other single supplier provided more than 10% of our product supply during fiscal 2013, however, NIC Holding Corp. and Phillips 66 each provided approximately 9% of our petroleum product purchases. For fiscal 2014, we generally have supply contracts for similar quantities with Global Companies LLC, JPMorgan Ventures Energy Corporation, NIC Holding Corp. and Phillips 66. Supply contracts typically have terms of 6 to 12 months. All of the supply contracts provide for minimum quantities. In all cases, the supply contracts do not establish in advance the price of home heating oil or propane. This price is based upon a published market index price at the time of delivery or pricing date plus an agreed upon differential. We believe that our policy of contracting for the majority of our anticipated supply needs with diverse and reliable sources will enable us to obtain sufficient product should unforeseen shortages develop in worldwide supplies.

Home Heating Oil Price Volatility

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

|  | Fiscal 2013 (1) |  |  | Fiscal 2012 |  |  | Fiscal 2011 |  |  | Fiscal 2010 |  |  | Fiscal 2009 |
|  | Low |  |  | High |  |  | Low |  |  | High |  |  | Low |  |  | High |  |  | Low |  |  | High |  |  | Low |  |  | High |
Quarter Ended |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
December 31 |  | $ | 2.90 |  |  | $ | 3.26 |  |  | $ | 2.72 |  |  | $ | 3.17 |  |  | $ | 2.19 |  |  | $ | 2.54 |  |  | $ | 1.78 |  |  | $ | 2.12 |  |  | $ | 1.20 |  |  | $ | 2.85 |
March 31 |  |  | 2.86 |  |  |  | 3.24 |  |  |  | 2.99 |  |  |  | 3.32 |  |  |  | 2.49 |  |  |  | 3.09 |  |  |  | 1.89 |  |  |  | 2.20 |  |  |  | 1.13 |  |  |  | 1.63 |
June 30 |  |  | 2.74 |  |  |  | 3.09 |  |  |  | 2.53 |  |  |  | 3.25 |  |  |  | 2.75 |  |  |  | 3.32 |  |  |  | 1.87 |  |  |  | 2.35 |  |  |  | 1.31 |  |  |  | 1.86 |
September 30 |  |  | 2.87 |  |  |  | 3.21 |  |  |  | 2.68 |  |  |  | 3.24 |  |  |  | 2.77 |  |  |  | 3.13 |  |  |  | 1.92 |  |  |  | 2.24 |  |  |  | 1.50 |  |  |  | 1.96 |

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

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Acquisitions

Part of our business strategy is to pursue select acquisitions. During fiscal 2013, the Partnership completed two acquisitions and added approximately 2,000 home heating oil and propane accounts for an aggregate cost of approximately $1.4 million, reduced by working capital credits of $0.1 million. In fiscal 2012, we acquired seven retail heating oil dealers with approximately 41,000 home heating oil and propane accounts for an aggregate cost of approximately $39.2 million, reduced by working capital credits of $1.2 million. In fiscal 2011, we acquired four retail heating oil dealers with approximately 8,800 home heating oil and propane accounts for an aggregate cost of approximately $9.7 million, including working capital of $1.9 million.

Employees

As of September 30, 2013, we had 2,577 employees, of whom 747 were office, clerical and customer service personnel; 776 were equipment technicians; 386 were fuel delivery drivers and mechanics; 377 were management and 291 were employed in sales. Of these employees 866 are represented by 45 different collective bargaining agreements with local chapters of labor unions. Some of these unions have union administered pension plans that have significant unfunded liabilities, a portion of which could be assessed to us should we withdraw from these plans. The Partnership does not expect to withdraw from these plans. Depending on the demands of the 2014 heating season, we anticipate that we will augment our current staffing levels from the 483 employees on leave (330 of whom are represented by collective bargaining agreements with labor unions). We are currently involved in union negotiations with three local bargaining units. We believe that our relations with both our union and non-union employees are generally satisfactory.

Government Regulations

We are subject to various federal, state and local environmental, health and safety laws and regulations. Generally, these laws impose limitations on the discharge or emission of pollutants and establish standards for the handling of solid and hazardous wastes. These laws include the Resource Conservation and Recovery Act, the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), the Clean Air Act, the Occupational Safety and Health Act, the Emergency Planning and Community Right to Know Act, the Clean Water Act and comparable state statutes. CERCLA, also known as the “Superfund” law, imposes joint and several liabilities without regard to fault or the legality of the original conduct on certain classes of persons that are considered to have contributed to the release or threatened release of a hazardous substance into the environment. Products stored and/or delivered by us and certain automotive waste products generated by our fleet are hazardous substances within the meaning of CERCLA or otherwise subject to investigation and cleanup under other environmental laws and regulations. While we are currently not involved with any material CERCLA claims, and we have implemented programs and policies designed to address potential liabilities and costs under applicable environmental laws and regulations, failure to comply with such laws and regulations could result in civil or criminal penalties in cases of non-compliance or impose liability for remediation costs.

We have incurred and continue to incur costs to address soil and groundwater contamination at some of our locations, including legacy contamination at properties that we have acquired. A number of our properties are currently undergoing remediation, in some instances funded by prior owners or operators contractually obligated to do so. To date, no material issues have arisen with respect to such prior owners or operators addressing such remediation, although there is no assurance that this will continue to be the case. In addition, we have been subject to proceedings by regulatory authorities for alleged violations of environmental and safety laws and regulations. We do not expect any of these liabilities or proceedings of which we are aware to result in material costs to, or disruptions of, our business or operations.

In addition, transportation of our products by truck are subject to regulations promulgated under the Federal Motor Carrier Safety Act. These regulations cover the transportation of hazardous materials and are administered by the United States Department of Transportation or similar state agencies. We conduct ongoing training programs to help ensure that our operations are in compliance with applicable safety regulations. We maintain various permits that are necessary to operate some of our facilities, some of which may be material to our operations.

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ITEM 1A. | RISK FACTORS

You should consider carefully the risk factors discussed below, as well as all other information, as an investment in the Partnership involves a high degree of risk. Any of the risks described below could impair our business, financial condition and operating results, which could result in a partial or total loss of your investment.

Our operating results will be adversely affected if we continue to experience significant net attrition in our home heating oil and propane customer base.

The following table depicts our gross customer gains, gross customer losses and net customer attrition from fiscal year 2009 to fiscal year 2013. 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 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. Starting October 1, 2010, we have included propane customers in this calculation as several of our acquisitions since such date have included propane operations.

|  | Fiscal Year Ended September 30, |
|  | 2013 |  |  | 2012 |  |  | 2011 |  |  | 2010 (a) |  |  | 2009 (a) |
Gross customer gains |  |  | 14.8 | % |  |  | 13.4 | % |  |  | 13.2 | % |  |  | 11.6 | % |  |  | 13.5 | %
Gross customer losses |  |  | 18.1 | % |  |  | 18.3 | % |  |  | 16.7 | % |  |  | 16.6 | % |  |  | 21.1 | %
Net attrition |  |  | (3.3 | %) |  |  | (4.9 | %) |  |  | (3.5 | %) |  |  | (5.0 | %) |  |  | (7.6 | %)(b)

(a) | Prior to October 1, 2010, we measured only home heating oil net customer attrition.

(b) | As a result of significant decreases in the price of home heating oil following the summer of 2008, we believe that approximately 10,000 price-protected customers in fiscal year 2009, chose another supplier due to being billed the termination fee for canceling their arrangement with us.

The gain of a new customer does not fully compensate for the loss of an existing customer because of the expenses incurred during the first year to acquire a new customer. Customer losses are the result of various factors, including but not limited to:

| • |  | price competition;

| • |  | customer relocations and home sales/foreclosures;

| • |  | conversions to natural gas; and

| • |  | credit worthiness.

The continuing volatility in the energy markets has intensified price competition and added to our difficulty in reducing net customer attrition.

If we are not able to reduce the current level of net customer attrition or if such level should increase, it will have a material adverse effect on our business, operating results and cash available for distributions to unitholders. For additional information about customer attrition, see Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Customer Attrition.”

Because of the highly competitive nature of our business, we may not be able to retain existing customers or acquire new customers, which would have an adverse impact on our business, operating results and financial condition.

Our business is subject to substantial competition. Most of our operating locations compete with numerous distributors, primarily on the basis of price, reliability of service and responsiveness to customer service needs. Each operating location operates in its own competitive environment.

We compete with distributors offering a broad range of services and prices, from full-service distributors, such as ourselves, to those offering delivery only. As do many companies in our business, we provide home heating equipment repair service on a 24-hour-a-day, seven-day-a-week, 52 weeks a year basis. We believe that this tends to build customer loyalty. In some instances homeowners have formed buying cooperatives that seek to purchase home heating oil from distributors at a price lower than individual customers are otherwise able to obtain. We also compete for retail customers with suppliers of alternative energy products, principally natural gas, propane (in the case of our home heating oil operations) and electricity. If we are unable to compete effectively, we may lose existing customers and/or fail to acquire new customers, which would have a material adverse effect on our business, operating results and financial condition.

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The following table depict our customer losses to natural gas conversions from fiscal year 2009 to fiscal year 2013. Conversions to natural gas are increasing and we believe this may continue as natural gas has become significantly less expensive than home heating oil on an equivalent BTU basis. In addition, the states of New York, Connecticut and Pennsylvania are seeking to encourage homeowners to expand the use of natural gas as a heating fuel through legislation and regulatory efforts.

|  | Fiscal Year Ended September 30, |
|  | 2013 |  |  | 2012 |  |  | 2011 |  |  | 2010 |  |  | 2009 |
Customer losses to natural gas conversion |  |  | (2.4 | %) |  |  | (2.0 | %) |  |  | (1.5 | %) |  |  | (1.1 | %) |  |  | (1.5 | %)

In addition to our direct customer losses to natural gas competition, any conversion to natural gas by a heating oil consumer in our geographic footprint reduces the pool of available customers from which we can gain new heating oil customers, and could have a material adverse effect on our business, operating results and financial condition.

If we do not make acquisitions on economically acceptable terms, our future growth will be limited.

Our industry is not a growth industry because new housing generally uses natural gas when it is available, and competition has also increased from alternative energy sources. Accordingly, future growth will depend on our ability to make acquisitions on economically acceptable terms. We cannot assure that we will be able to identify attractive acquisition candidates in our sector in the future or that we will be able to acquire businesses on economically acceptable terms. Factors that may adversely affect our operating and financial results may limit our access to capital and adversely affect our ability to make acquisitions. Under the terms of our amended and restated revolving credit facility that we sometimes refer to in this Report as the revolving credit facility, we are restricted from making any individual acquisition in excess of $25.0 million without the lenders’ approval. In addition, to make an acquisition, we are required to have Availability (as defined in the revolving credit facility) of at least $40.0 million, on a historical pro forma and forward-looking basis. This covenant restriction may limit our ability to make acquisitions. Any acquisition may involve potential risks to us and ultimately to our unitholders, including:

| • |  | an increase in our indebtedness;

| • |  | an increase in our working capital requirements;

| • |  | an inability to integrate the operations of the acquired business;

| • |  | an inability to successfully expand our operations into new territories;

| • |  | the diversion of management’s attention from other business concerns;

| • |  | an excess of customer loss or loss of key employees from the acquired business; and

| • |  | the assumption of additional liabilities including environmental liabilities.

In addition, acquisitions may be dilutive to earnings and distributions to unitholders, and any additional debt incurred to finance acquisitions may, among other things, affect our ability to make distributions to our unitholders.

High product prices can lead to customer conservation and attrition, resulting in reduced demand for our products.

Prices for our products are subject to volatile fluctuations in response to changes in supply and other market conditions. During periods of high product costs our prices generally increase. High prices can lead to customer conservation and attrition, resulting in reduced demand for our products.

A significant portion of our home heating oil volume is sold to price-protected customers (ceiling and fixed) and our gross margins could be adversely affected if we are not able to effectively hedge against fluctuations in the volume and cost of product sold to these customers.

A significant portion of our home heating oil volume is sold to individual customers under an arrangement pre-establishing the ceiling sales price or a fixed price of home heating oil over a fixed period. When the customer makes a purchase commitment for the next period we currently purchase option contracts, swaps and futures contracts for a substantial majority of the heating oil that we expect to sell to these price-protected 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. If the actual usage exceeds the amount of the hedged volume on a monthly basis, we could be required to obtain additional volume at unfavorable margins. In addition, should actual usage in any month be less than the hedged volume, (including, for example, as a result of early terminations by fixed price customers) our hedging losses could be greater. Currently, we have elected not to designate our derivative instruments as hedging instruments under FASB ASC 815-10-05 Derivatives and Hedging, and the change in fair value of the derivative instruments is recognized in our statement of operations. Therefore, we experience volatility in earnings as these currently outstanding derivative contracts are marked to market and non-cash gains or losses are recorded in the statement of operations.

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Our risk management policies cannot eliminate all commodity risk, basis risk, or the impact of adverse market conditions which can adversely affect our financial condition, results of operations and cash available for distribution to our unitholders. In addition, any noncompliance with our risk management policies could result in significant financial losses.

While our hedging policies are designed to minimize commodity risk, some degree of exposure to unforeseen fluctuations in market conditions remains. For example, we change our hedged position daily in response to movements in our inventory. Any difference between the estimated future sales from inventory and actual sales will create a mismatch between the amount of inventory and the hedges against that inventory, and thus change the commodity risk position that the Partnership is trying to maintain. Also, significant increases in the costs of the products we sell can materially increase our costs to carry inventory. We use our credit facility as our primary source of financing to carry inventory and may be limited on the amounts we can borrow to carry inventory. Basis risk describes the inherent market price risk created when a commodity of certain grade or location is purchased, sold or exchanged as compared to a purchase, sale or exchange of a like commodity at a different time or place. Transportation costs and timing differentials are components of basis risk. For example, we use the NYMEX to hedge our commodity risk with respect to pricing of energy products traded on the NYMEX. Physical deliveries under NYMEX contracts are made in New York Harbor. To the extent we take deliveries in other ports, such as Boston Harbor, we may have basis risk. In a backward market (when prices for future deliveries are lower than current prices), basis risk is created with respect to timing. In these instances, physical inventory generally loses value as basis declines over time. Basis risk cannot be entirely eliminated, and basis exposure, particularly in backward or other adverse market conditions, can adversely affect our financial condition, results of operations and cash available for distribution to our unitholders.

We monitor processes and procedures to prevent unauthorized trading and to maintain substantial balance between purchases and sales or future delivery obligations. We can provide no assurance, however, that these steps will detect and/or prevent all violations of such risk management policies and procedures, particularly if deception or other intentional misconduct is involved.

The change in the NYMEX contract specifications from high sulfur home heating oil to ultra low sulfur diesel has increased the risks, costs and complexities of hedging.

Effective as of April 1, 2013 the NYMEX contract specifications were changed from high sulfur home heating oil to ultra low sulfur diesel. From April 1, 2013, to September 30, 2013, high sulfur home heating oil was sold at a discount to the NYMEX ultra low sulfur diesel of between $0.065 and $0.250 cents per gallon.

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

Since weather conditions may adversely affect the demand for home heating oil, our business, operating results and financial condition is vulnerable to warm winters.

Weather conditions in the Northeast and Mid-Atlantic regions in which we operate have a significant impact on the demand for home heating oil because our customers depend on this product principally for space heating purposes. As a result, weather conditions may materially adversely impact our business, operating results and financial condition. During the peak-heating season of October through March, sales of home heating oil and propane historically have represented approximately 80% of our annual oil volume. Actual weather conditions can vary substantially from year to year or from month to month, significantly affecting our financial performance. Warmer than normal temperatures in one or more regions in which we operate can significantly decrease the total volume we sell and the gross profit realized and, consequently, our results of operations. In fiscal years 2012 and 2002 temperatures were significantly warmer than normal for the areas in which we sell our products, which adversely affected the amount of net income, EBITDA and Adjusted EBITDA that we generated during these periods.

To partially mitigate the adverse effect of warm weather on cash flows, we have used weather hedge contracts for a number of years. In general, such weather hedge contracts provide that we are entitled to receive a specific payment per heating degree-day shortfall, when the total number of heating degree-days in the period covered is less than 92.5% of the ten year average (the “Payment Threshold”). The hedge generally covers the period from November 1, through March 31, of a fiscal year taken as a whole, and has a maximum payout amount. Temperatures in fiscal year 2012, taken as a whole met the Payment Threshold, and the heating degree-day shortfall during this period resulted in our receiving the full $12.5 million payout, which was recorded as a reduction of expenses in the line item delivery and branch expenses in the statements of operations. Temperatures in fiscal year 2013, taken as a whole did not meet the Payment Threshold and there was no payout under the weather hedge contract.

For the fiscal years 2014 and 2015, we have a weather hedge contract with Swiss Re Financial Products Corporation 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 92.5% of the ten year average, the Payment Threshold. The hedge covers the period from November 1, through March 31, taken as a whole, for each respective fiscal year, and has a maximum payout of $12.5 million for each respective fiscal year. However, there can be no assurance that such weather hedge contract would fully or substantially offset the adverse effects of warmer weather on our business and operating results during such periods.

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We experienced warmer than normal weather conditions in the fiscal 2012 heating season, which had an adverse effect on our fiscal 2012 results of operations and our financial condition.

In fiscal year 2012 temperatures were significantly warmer than normal for the areas in which we sell our products, which adversely affected the amount of net income, EBITDA and Adjusted EBITDA that we generated during this period. For those locations where we had existing operations in both periods, which we sometimes refer to as the “base business” (i.e., excluding acquisitions in the year made), temperatures (measured on a degree day basis) for fiscal 2012 were 21.4% warmer than the fiscal 2011 and 21.7% warmer than normal, as reported by the National Oceanic and Atmospheric Administration (“NOAA”).

Because of the adverse impact of warm weather in our market areas during the fiscal 2012 heating season even with the benefit of the weather hedge contract, our fixed charge coverage ratio for the twelve months ended March 31, 2012 was 1.14 versus the 1.15 required under our revolving credit facility for payments of distributions. As a result, in April 2012, we entered into an amendment to our revolving credit facility that permitted us to continue paying distributions to our unitholders for the period from April 1, 2012 through December 31, 2012, provided that our Availability (borrowing base less amounts borrowed and letters of credit Issued) was in excess of $50.0 million and provided that distributions made during such period did not exceed $0.2325 per common unit. During this period, we were not required to meet the fixed charge coverage test to pay distributions but were required to meet the fixed charge coverage test of 1.15 to repurchase units in addition to having an Availability of $61.3 million. In order to pay distributions subsequent to December 31, 2012, we must maintain an availability of $61.3 million, 17.5% of the maximum facility size on a historical pro forma and forward looking basis, and have a fixed charge coverage ratio of 1.15. Our fiscal year ended September 30, 2012, fixed charge coverage ratio was in excess of 1.15.

We participate in multiemployer pension plans whose costs represent a significant expense to us.

We participate in a number of trustee-managed multiemployer pension plans for employees covered under collective bargaining agreements. Several factors could cause us to make significantly higher future contributions to these plans, including unfavorable investment performance, insolvency of participating employers, changes in demographics and increased benefits to participants. Some of these unions have union administered pension plans that have significant unfunded liabilities, a portion of which could be assessed to us should we withdraw from these plans. However, we do not expect to withdraw from these plans. At this time, we are unable to determine whether any material adverse effect on our financial condition, results of operations or liquidity will result from our participation in these plans.

We rely on the continued solvency of our derivatives, insurance and weather hedge counterparties.

If counterparties to the derivative instruments that we use to hedge the cost of home heating oil sold to price-protected customers, physical inventory and our vehicle fuel costs were to fail, our liquidity, operating results and financial condition could be materially adversely impacted, as we would be obligated to fulfill our operational requirement of purchasing, storing and selling home heating oil and vehicle fuel, while losing the mitigating benefits of economic hedges with a failed counterparty. If one of our insurance carriers were to fail, our liquidity, results of operations and financial condition could be materially adversely impacted, as we would have to fund any catastrophic loss. If our weather hedge counterparty were to fail, we would lose the protection of our weather hedge contract in case of warmer than normal weather. Currently, we have outstanding derivative instruments with the following counterparties: Bank of America, N.A., Bank of Montreal, Cargill, Inc., Citibank, N.A., JPMorgan Chase Bank, N.A., Key Bank, N.A., Regions Financial Corporation, Societe Generale, and Wells Fargo Bank, N.A. Our primary insurance carrier is American International Group and our weather hedge counterparty is Swiss Re Financial Products Corporation.

Our operating results are subject to seasonal fluctuations.

Our operating results are subject to seasonal fluctuations since the demand for home heating oil and propane is greater during the first and second fiscal quarter of our fiscal year, which is the peak heating season. The seasonal nature of our business has resulted on average in 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 of each fiscal year. As a result, we generally realize net income in our first and second fiscal quarters and net losses during our third and fourth fiscal quarters and we expect that the negative impact of seasonality on our third and fourth fiscal quarter operating results will continue. Thus any material reduction in the profitability of the first and second quarters for any reason, including warmer than normal weather, generally cannot be made up by any significant profitability improvements in the results of the third and fourth quarters.

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Our substantial debt and other financial obligations could impair our financial condition and our ability to fulfill our debt obligations.

At September 30, 2013, we had outstanding $125.0 million (excluding discount) of senior notes due 2017 (the “notes”), no amount outstanding under our revolving credit facility which expires June 2016, $44.7 million of letters of credit issued under our revolving credit facility and availability of $164.3 million under such revolving credit facility. During the last three fiscal years we have utilized as much as $156.3 million of our revolving credit facility in borrowings and letters of credit. Our substantial indebtedness and other financial obligations could:

| • |  | impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, unit repurchases or general partnership purposes;

| • |  | have a material adverse effect on us if we fail to comply with financial and affirmative and restrictive covenants in our debt agreements and an event of default occurs that is not cured or waived;

| • |  | require us to dedicate a substantial portion of our cash flow for interest payments on our indebtedness and other financial obligations, thereby reducing the availability of our cash flow to fund working capital and capital expenditures;

| • |  | limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and

| • |  | place us at a competitive disadvantage compared to our competitors that have proportionally less debt.

If we are unable to meet our debt service obligations and other financial obligations, we could be forced to restructure or refinance our indebtedness and other financial transactions, seek additional equity capital or sell our assets. We might then be unable to obtain such financing or capital or sell our assets on satisfactory terms, if at all.

Increases in wholesale product costs beyond current levels may have adverse effects on our business, financial condition and results of operations.

Increases in wholesale product costs beyond current levels may have adverse effects on our business, financial condition and results of operations, including the following:

| • |  | customer conservation or attrition due to customers converting to lower cost heating products or suppliers;

| • |  | reduced liquidity as a result of higher receivables, and/or inventory balances as we must fund a portion of any increase in receivables, inventory and hedging costs from our own resources, thereby tying up funds that would otherwise be available for other purposes;

| • |  | higher bad debt expense and credit card processing costs as a result of higher selling prices;

| • |  | higher interest expense as a result of increased working capital borrowing to finance higher receivables and/or inventory balances; and

| • |  | higher vehicle fuel costs.

The volatility in wholesale energy costs may adversely affect our liquidity.

Our business requires a significant amount of working capital to finance accounts receivable and inventory during the heating season. Under our revolving credit facility, we may borrow up to $250 million, which increases to $350 million during the peak winter months from December through April of each fiscal year. We are obligated to meet certain financial covenants under the revolving credit facility, including the requirement to maintain at all times either excess availability (borrowing base less amounts borrowed and letters of credit issued) of 12.5% of the revolving credit commitment then in effect or a fixed charge coverage ratio (as defined in the revolving credit facility agreement) of not less than 1.1.

If increases in wholesale product costs cause our working capital requirements to exceed the amounts available under our revolving credit facility or should we fail to maintain the required availability or fixed charge coverage ratio, we would not have sufficient working capital to operate our business, which could have a material adverse effect on our financial condition and results of operations.

We purchase synthetic call options and forward swaps with members of our lending group to manage market risk associated with our commitments to our customers, our physical inventory and fuel we use for our vehicles. These institutions have not required an initial cash margin deposit or any mark to market maintenance margin for these derivatives. Any mark to market exposure is reserved against our borrowing base and can thus reduce the amount available to us under our revolving credit facility. The mark to market reserve against our borrowing base for these derivative instruments with our lending group was as high as $13.8 million, $16.1 million, and $9.4 million during fiscal years 2013, 2012 and 2011, respectively.

We also purchase call options to hedge the price of the products to be sold to our price-protected customers which usually require us to pay an up front cash payment. This reduces our liquidity, as we must pay for the option before any sales are made to the customer. We also purchase synthetic call options which require us to pay for these options as they expire.

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For certain of our supply contracts, we are required to establish the purchase price in advance of receiving the physical product. This occurs at the end of the month and is usually 20 days prior to receipt of the product. We use futures contracts or swaps to “short” the purchase commitment such that the commitment floats with the market. As a result, any upward movement in the market for home heating oil would reduce our liquidity, as we would be required to post additional cash collateral for a futures contract or our availability to borrow under our bank facility would be reduced in the case of a swap. At December 31, 2013, we expect to have approximately 40 million gallons of purchase commitments and physical inventory shorted with a futures contract or swap. If the wholesale price of heating oil increased $1.00 per gallon , our near term liquidity in December would be reduced by $40 million.

At September 30, 2013, we had approximately 137,000 customers, or 38% of our residential customer base, on the balanced payment plan. Volatility in wholesale prices could reduce our liquidity if we failed to recalculate the balanced payments on a timely basis or if customers resist higher balanced payments. These customers could possibly owe us more in the future than we had budgeted. Generally, customer credit balances are at their low point after the end of the heating season and at their peak prior to the beginning of the heating season.

Sudden and sharp oil price increases that cannot be passed on to customers may adversely affect our operating results.

Our industry is a “margin-based” business in which gross profit depends on the excess of sales prices per gallon over supply costs per gallon. Consequently, our profitability is sensitive to changes in the wholesale product cost caused by changes in supply or other market conditions. These factors are beyond our control and thus, when there are sudden and sharp increases in the wholesale cost of home heating oil, we may not be able to pass on these increases to customers through increased retail sales prices. In an effort to retain existing accounts and attract new customers we may offer discounts, which will impact the net per gallon gross margin realized.

Significant declines in the wholesale price of home heating oil may cause price-protected customers to renegotiate or terminate their arrangements which may adversely impact our gross profit and operating results.

When the wholesale price of home heating oil declines significantly after a customer enters into a price protection arrangement, some customers attempt to renegotiate their arrangement in order to enter into a lower cost pricing plan with us or terminate their arrangement and switch to a competitor. As a result of significant decreases in the price of home heating oil following the summer of 2008, many price-protected customers attempted to renegotiate their agreements with us in fiscal 2009. It is our policy to bill a termination fee when customers terminate their arrangement with us. We believe that approximately 10,000 customers chose another supplier as a result of being billed the termination fee in fiscal 2009.

Current economic conditions could adversely affect our results of operations and financial condition.

Uncertainty about current economic conditions poses a risk as our customers may reduce or postpone spending in response to tighter credit, negative financial news and/or declines in income or asset values, which could have a material negative effect on the demand for our equipment and services and could lead to increased conservation, as we have seen certain of our customers seek lower cost providers. Any increase in existing customers or potential new customers seeking lower cost providers and/or increase in our rejection rate of potential accounts because of credit considerations could increase our overall rate of net customer attrition. In addition, we could experience an increase in bad debts from financially distressed customers, which would have a negative effect on our liquidity, results of operations and financial condition.

We are subject to operating and litigation risks that could adversely affect our operating results whether or not covered by insurance.

Our operations are subject to all operating hazards and risks normally incidental to handling, storing, transporting and otherwise providing customers with our products, which include combustible liquids such as propane. As a result, we may be a defendant in legal proceedings and litigation arising in the ordinary course of business.

We maintain insurance policies with insurers in amounts and with coverage and deductibles that we believe are reasonable. However, there can be no assurance that this insurance will be adequate to protect us from all material expenses related to potential future claims for remediation costs and personal and property damage or that these levels of insurance will be available in the future at economical prices.

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Our operations are subject to operational hazards and our insurance reserves may not be adequate to cover actual losses.

In storing and delivering product to our customers, our operations are subject to operational hazards such as natural disasters, adverse weather, accidents, fires, explosions, hazardous materials releases, mechanical failures and other events beyond our control. If any of these events were to occur, we could incur substantial losses because of personal injury or loss of life, severe damage to and destruction of property and equipment, and pollution or other environmental damage resulting in curtailment or suspension of our related operations.

As we self-insure workers’ compensation, automobile and general liability claims up to pre-established limits, we establish reserves based upon expectations as to what our ultimate liability will be for claims based on our historical developmental factors. We evaluate on an annual basis the potential for changes in loss estimates with the support of qualified actuaries. As of September 30, 2013, we had approximately $51.3 million of net insurance reserves and had issued $42.5 million in letters of credit for current and future claims. The ultimate settlement of these claims could differ materially from the assumptions used to calculate the reserves, which could have a material effect on our results of operations.

Our results of operations and financial condition may be adversely affected by governmental regulation and associated environmental and regulatory costs.

Our business is subject to a wide range of federal and state laws and regulations related to environmental and other matters. Such laws and regulations have become increasingly stringent over time. We may experience increased costs due to stricter pollution control requirements or liabilities resulting from noncompliance with operating or other regulatory permits. New regulations might adversely impact operations, including those relating to underground storage and transportation of the products that we sell. In addition, there are environmental risks inherently associated with home heating oil operations, such as the risks of accidental releases or spills. We have incurred and continue to incur costs to remediate soil and groundwater contamination at some of our locations. We cannot be sure that we have identified all such contamination, that we know the full extent of our obligations with respect to contamination of which we are aware, or that we will not become responsible for additional contamination not yet discovered. It is possible that material costs and liabilities will be incurred, including those relating to claims for damages to property and persons.

In addition, our financial condition, results of operations and ability to pay distributions to our unitholders may be negatively impacted by significant changes in federal and state tax law.

There is increasing attention in the United States and worldwide concerning the issue of climate change and the effect of emissions of greenhouse gases, in particular from the combustion of fossil fuels. It is probable that any regulatory program that caps emissions or imposes a carbon tax will increase costs for us and our customers, which could lead to increased conservation or customers seeking lower cost alternatives. However, we cannot yet estimate the compliance costs or business impact of potential national, regional or state greenhouse gas emissions reduction legislation, regulations or initiatives, since such programs and proposals are in the early stages of development.

Energy efficiency and new technology may reduce the demand for our products and adversely affect our operating results.

Increased conservation and technological advances, including installation of improved insulation and the development of more efficient furnaces and other heating devices, have adversely affected the demand for our products by retail customers. Future conservation measures or technological advances in heating, conservation, energy generation or other devices might reduce demand and adversely affect our operating results.

Our operations would be adversely affected if service at our third-party terminals or on the common carrier pipelines used is interrupted.

The products that we sell are transported in either barge, pipeline or in truckload quantities to third-party terminals where we have contracts to temporarily store our products. Any significant interruption in the service of these third-party terminals or on the common carrier pipelines used would adversely affect our ability to obtain product.

The risk of global terrorism and political unrest may adversely affect the economy and the price and availability of the products that we sell and have a material adverse effect on our business, financial condition and results of operations.

Terrorist attacks and political unrest may adversely impact the price and availability of the products that we sell, our results of operations, our ability to raise capital and our future growth. The impact that the foregoing may have on our industry in general, and on our business in particular, is not known at this time. An act of terror could result in disruptions of crude oil supplies, markets and facilities, and the source of the products that we sell could be direct or indirect targets. Terrorist activity may also hinder our ability to transport our products if our normal means of transportation become damaged as a result of an attack. Instability in the financial markets as a result of terrorism could also affect our ability to raise capital. Terrorist activity could likely lead to increased volatility in the prices of our products.

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The impact of hurricanes and other natural disasters could cause disruptions in supply and could also reduce the demand for home heating oil which would have a material adverse effect on our business, financial condition and results of operations.

Hurricanes and other natural disasters may cause disruptions in the supply chains for home heating oil and other products that we sell. Disruptions in supply could have a material adverse effect on our business, financial condition and results of operations, causing an increase in wholesale prices and a decrease in supply. Hurricanes and other natural disasters could also cause disruptions in the power grid, which could prevent our customers from operating their home heating oil systems, thereby reducing our sales. For example, on October 29, 2012, storm Sandy made landfall in our service area, resulting in widespread power outages that affected a number of our customers. Deliveries of home heating oil and propane were less than expected for certain of our customers who were without power for several weeks subsequent to storm Sandy.

Conflicts of interest have arisen and could arise in the future.

Conflicts of interest have arisen and could arise in the future as a result of relationships between the general partner and its affiliates, on the one hand, and us or any of our limited partners and noteholders, on the other hand. As a result of these conflicts the general partner may favor its own interests and those of its affiliates over the interests of the unitholders and noteholders. The nature of these conflicts is ongoing and includes the following considerations:

| • |  | The general partner’s affiliates are not prohibited from engaging in other business or activities, including direct competition with us.

| • |  | The general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings and reserves, each of which can impact the amount of cash, if any, available for distribution to unitholders, and available to pay principal and interest on debt and the amount of incentive distributions payable in respect of the general partner units.

| • |  | The general partner controls the enforcement of obligations owed to us by the general partner.

| • |  | The general partner decides whether to retain separate counsel or others to perform services for us.

| • |  | In some instances the general partner may borrow funds in order to permit the payment of distributions to unitholders.

| • |  | The general partner may limit its liability and reduce its fiduciary duties, while also restricting the remedies available to unitholders for actions that might, without limitations, constitute breaches of fiduciary duty. Unitholders are deemed to have consented to some actions and conflicts of interest that might otherwise be deemed a breach of fiduciary or other duties under applicable state law.

| • |  | The general partner is allowed to take into account the interests of parties in addition to the Partnership in resolving conflicts of interest, thereby limiting its fiduciary duty to the unitholders.

| • |  | The general partner determines whether to issue additional units or other of our securities.

| • |  | The general partner determines which costs are reimbursable by us.

| • |  | The general partner is not restricted from causing us to pay the general partner or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf.

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Cash distributions (if any) are not guaranteed and may fluctuate with performance and reserve requirements.

Distributions of available cash by us to unitholders will depend on the amount of cash generated, and distributions may fluctuate based on our performance. The actual amount of cash that is available will depend upon numerous factors, including:

| • |  | profitability of operations,

| • |  | required principal and interest payments on debt or debt prepayments,

| • |  | debt covenants,

| • |  | margin account requirements,

| • |  | cost of acquisitions,

| • |  | issuance of debt and equity securities,

| • |  | fluctuations in working capital,

| • |  | capital expenditures,

| • |  | units repurchased,

| • |  | adjustments in reserves,

| • |  | prevailing economic conditions,

| • |  | financial, business and other factors,

| • |  | increased pension funding requirements,

| • |  | the amount of our net operating loss carry forwards (as subject to any Section 382 limitation and utilization), and

| • |  | the amount of cash taxes we have to pay in Federal, State and local corporate income and franchise taxes.

Our operations are conducted through Petro Holdings, Inc. (a Minnesota corporation that is our indirect wholly owned subsidiary) and its subsidiaries, all of which are corporations subject to federal and state income taxes filed on a calendar year basis. At December 31, 2012, our federal Net Operating Loss carryforwards (“NOLs”) were $10.6 million, subject to annual limitations on the amount of losses that can be used of between $1.0 million and $2.2 million.

Most of these factors are beyond the control of the general partner. Our Partnership Agreement gives the general partner discretion in establishing reserves for the proper conduct of our business, including acquisitions. These reserves will also affect the amount of cash available for distribution.

Our revolving credit facility and the indenture for our notes, both impose certain restrictions on our ability to pay distributions to unitholders. The most restrictive covenant is found in the revolving credit facility. In order to make any distributions to unitholders, we must maintain availability of 17.5% of the maximum facility size and a fixed charge coverage ratio of not less than 1.15, which is based on Adjusted EBITDA. (See Note 11 of the Notes to the Consolidated Financial Statements—Long-Term Debt and Bank Facility Borrowings)

Unitholders have in the past and may in the future have to report income for Federal income tax purposes on their investment in us without receiving any cash distributions from us.

Star Gas Partners is a master limited partnership. Currently, our main asset and source of income is our 100% ownership interest in Star Acquisitions, Inc. (“Star Acquisitions”), which is the parent company of Petro Holdings, Inc. Our unitholders do not receive any of the tax benefits normally associated with owning units in a publicly traded partnership, as any cash coming from Star Acquisitions to us will generally have been taxed first at a corporate level and then may also be taxable to our unitholders as dividends, reported via annual Forms K-1. We expect that an investor will be allocated taxable income (mostly dividend income from Star Acquisitions, interest income and possibly cancellation of indebtedness income) regardless of whether a cash distribution has been paid. Our unitholders are required to report for Federal income tax purposes their allocable share of our income, gains, losses, deductions and credits, regardless of whether we make cash distributions. For example, our unitholders had $20.3 million in dividend income reported on their 2012 K-1’s related to dividends received by us that we used to repurchase units.

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We are a holding company and have no material operations or assets. Accordingly, we are dependent on distributions from our subsidiaries to service our debt obligations. These distributions are not guaranteed and may be restricted. In addition, the notes are non-recourse to our subsidiaries.

We are a holding company for our direct and indirect subsidiaries. We have no material operations and only limited assets. Accordingly, we are dependent on cash distributions from our subsidiaries to service our debt obligations. Noteholders will not receive payments required by the notes unless our subsidiaries are able to make distributions to us after they first comply with the restrictions on distributions under the terms of their own borrowing arrangements and reserve any necessary amounts to meet their own financial obligations.

Additionally, our obligations under the notes are non-recourse to our subsidiaries. Therefore, if we should fail to pay interest or principal on the notes or breach any of our other obligations under the notes or the indenture, noteholders would not be able to obtain any such payments or obtain any other remedy from our subsidiaries, which are not liable for any of our obligations under the indenture or the notes.

We are not required to accumulate cash for the purpose of meeting our future obligations to our noteholders, which may limit the cash available to service our notes.

Subject to the limitations on restricted payments that are contained in the revolving credit facility and in the indenture governing the notes, we are not required to accumulate cash for the purpose of meeting our future obligations to our noteholders. As a result, we do not expect to accumulate significant amounts of cash and anticipate that we will be required to refinance the notes prior to their maturity. Our ability to refinance the notes will depend upon our future results of operation and financial condition as well as developments in the capital markets. Our general partner will determine the future use of our cash resources and has broad discretion in determining such uses and in establishing reserves for such uses, which may include but are not limited to:

| • |  | complying with the terms of any of our agreements or obligations;

| • |  | providing for distributions of cash to our unitholders in accordance with the requirements of our Partnership Agreement;

| • |  | providing for future capital expenditures and other payments deemed by our general partner to be necessary or advisable, including to make acquisitions; and

| • |  | repurchasing common units.

Depending on the timing and amount our use of cash, this could significantly reduce the cash available to us in subsequent periods to make payments on the notes.

The notes are structurally subordinated to all indebtedness and other liabilities of our subsidiaries.

The notes are structurally subordinated to all existing and future claims of creditors of our subsidiaries, including the lenders under our revolving credit facility, their trade creditors and all of their possible future creditors. This is because these creditors will have priority as to the assets of our subsidiaries over our claims as a direct or indirect equity holder in our subsidiaries and, thereby, indirect priority over noteholder claims. As a result, upon any distribution to these creditors in a bankruptcy, liquidation or reorganization or similar proceeding relating to us or our property, these creditors will be entitled to be paid in full before any payment may be made with respect to the notes. Thereafter, the holders of the notes will participate with our trade creditors and all other holders of our senior indebtedness in the assets remaining, if any. In any of these cases, we may have insufficient funds to pay all of our creditors and noteholders may therefore receive less, ratably, than creditors of our subsidiaries. As of September 30, 2013, the notes ranked structurally junior to $245.2 million of indebtedness and other liabilities of our subsidiaries.

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Restrictive covenants in the agreements governing our indebtedness and other financial obligations of our subsidiaries may reduce our operating flexibility.

The indenture governing our notes and the revolving credit facility agreement contain various covenants that limit our ability and the ability of specified subsidiaries of ours to, among other things:

| • |  | incur additional indebtedness;

| • |  | make distributions to our unitholders;

| • |  | purchase or redeem our outstanding equity interests or subordinated debt;

| • |  | make specified investments;

| • |  | create liens;

| • |  | sell assets;

| • |  | engage in specified transactions with affiliates;

| • |  | restrict the ability of our subsidiaries to make specified payments, loans, guarantees and transfers of assets or interests in assets;

| • |  | engage in sale-leaseback transactions;

| • |  | effect a merger or consolidation with or into other companies or a sale of all or substantially all of our properties or assets; and

| • |  | engage in other lines of business.

These restrictions could limit our ability to obtain future financings, make needed capital expenditures, withstand a future downturn in our business or the economy in general, conduct operations or otherwise take advantage of business opportunities that may arise. The agreements also require us to maintain specified financial ratios and satisfy other financial conditions. Our ability to meet those financial ratios and conditions can be affected by events beyond their control, such as weather conditions and general economic conditions. Accordingly, we may be unable to meet those ratios and conditions.

Any breach of any of these covenants or failure to meet any of these ratios or conditions could result in a default under the terms of the relevant indebtedness or other financial obligations, which could cause such indebtedness or other financial obligations, and by reason of cross-default provisions, the notes, to become immediately due and payable. If we were unable to repay those amounts, the lenders could initiate a bankruptcy proceeding or liquidation proceeding or proceed against the collateral, if any. If the lenders of our indebtedness or other financial obligations accelerate the repayment of borrowings or other amounts owed, we may not have sufficient assets to repay our indebtedness or other financial obligations, including the notes.

We may be unable to repurchase the notes upon a change of control and it may be difficult to determine if a change of control has occurred.

Upon the occurrence of “change of control” as defined in the indenture for the notes, we or a third party will be required to make a change of control offer to repurchase the notes at 101% of their principal amount, plus accrued and unpaid interest. The terms of our indebtedness limit our ability to repurchase the notes in those circumstances. Any of our future debt agreements may contain similar restrictions and provisions. Accordingly, we may be unable to satisfy our obligations to purchase the notes unless we are able to refinance or obtain waivers under our indebtedness. We may not have the financial resources to purchase the notes, particularly if a change of control event triggers a similar repurchase requirement for, or results in the acceleration of, other indebtedness. Our failure to make or consummate a change of control repurchase offer or pay the change of control purchase price when due will give the trustee and the holders of the notes certain default rights as set forth in the indenture.

Our obligations under the revolving credit facility (as of September 30, 2013, no amount was outstanding under the revolving credit facility, $44.7 million of letters of credit were issued and we had availability of $164.3 million) are subject to change of control provisions at least as restrictive as the change of control provisions under the notes. Accordingly, any event which would be a “change of control” under the senior notes would also be a “change of control” under such other indebtedness. We are not restricted from entering into a transaction that would trigger the change of control provisions. If these change of control provisions are triggered, some of the outstanding debt may become due. It is possible that we would not have sufficient funds at the time of any change of control to make the required debt payments or that restrictions in other debt instruments would not permit those payments. In some instances, lenders would have the right to foreclose on our assets if debt payments were not made upon a change of control.

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A lowering or withdrawal of the ratings assigned to our debt securities by rating agencies may increase our future borrowing costs and reduce our access to capital.

Our debt currently has a non-investment grade rating, and any rating assigned could be lowered or withdrawn entirely by a rating agency if, in that rating agency’s judgment, future circumstances relating to the basis of the rating, such as adverse changes, so warrant. Consequently, real or anticipated changes in our credit ratings will generally affect the market value of the notes. Credit ratings are not recommendations to purchase, hold or sell the notes. Additionally, credit ratings may not reflect the potential effect of risks relating to the structure or marketing of the notes. Any downgrade by either Standard & Poor’s or Moody’s Investors Service would increase the interest rate on our revolving credit facility, decrease earnings and may result in higher borrowing costs.

Any future lowering of our ratings likely would make it more difficult or more expensive for us to obtain additional debt financing. If any credit rating initially assigned to the notes is subsequently lowered or withdrawn for any reason, noteholders may not be able to resell their notes without a substantial discount.

ITEM 1B. | UNRESOLVED STAFF COMMENTS

Not applicable.

ITEM 2. | PROPERTIES

We provide services to our customers in the United States from Maine to South Carolina from 35 principal operating locations and 72 depots, 31 of which are owned and 76 of which are leased. As of September 30, 2013, we had a fleet of 998 truck and transport vehicles, the majority of which were owned and 1,066 service vans, the majority of which were leased. We lease our corporate headquarters in Stamford, Connecticut. Our obligations under our revolving credit facility are secured by liens and mortgages on substantially all of the Partnership’s and subsidiaries’ real and personal property.

ITEM 3. | LEGAL PROCEEDINGS—LITIGATION

We are involved from time to time in litigation incidental to the conduct of our business, but we are not currently a party to any material lawsuit or proceeding.

ITEM 4. | MINE SAFETY DISCLOSURES

Not applicable.

PART II

ITEM 5. | MARKET FOR REGISTRANT’S UNITS AND RELATED MATTERS

The common units, representing limited partner interests in the Partnership, are listed and traded on the New York Stock Exchange, Inc. (“NYSE”) under the symbol “SGU”.

The following tables set forth the high and low closing price ranges for the common units and the cash distribution declared on each unit for the fiscal 2013 and 2012 quarters indicated.

|  | SGU – Common Unit Price Range |  |  | Distributions Declared |
|  | High |  |  | Low |  |  | per Unit |
|  | Fiscal Year 2013 |  |  | Fiscal Year 2012 |  |  | Fiscal Year 2013 |  |  | Fiscal Year 2012 |  |  | Fiscal Year 2013 |  |  | Fiscal Year 2012 |
Quarter Ended |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
December 31, |  | $ | 4.36 |  |  | $ | 5.15 |  |  | $ | 3.98 |  |  | $ | 4.70 |  |  | $ | 0.0775 |  |  | $ | 0.0775 |
March 31, |  | $ | 4.90 |  |  | $ | 4.88 |  |  | $ | 4.13 |  |  | $ | 4.09 |  |  | $ | 0.0775 |  |  | $ | 0.0775 |
June 30, |  | $ | 5.02 |  |  | $ | 4.19 |  |  | $ | 4.48 |  |  | $ | 3.66 |  |  | $ | 0.0825 |  |  | $ | 0.0775 |
September 30, |  | $ | 5.07 |  |  | $ | 4.52 |  |  | $ | 4.73 |  |  | $ | 4.11 |  |  | $ | 0.0825 |  |  | $ | 0.0775 |

As of November 30, 2013, there were approximately 340 holders of record of common units.

There is no established public trading market for the Partnership’s 0.3 million general partner units.

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Partnership Distribution Provisions

We are required to make distributions in an amount equal to our Available Cash, as defined in our Partnership Agreement, no more than 45 days after the end of each fiscal quarter, to holders of record on the applicable record dates. Available Cash, as defined in our Partnership Agreement, generally means all cash on hand at the end of the relevant fiscal quarter less the amount of cash reserves established by the Board of Directors of our general partner in its reasonable discretion for future cash requirements. These reserves are established for the proper conduct of our business, including the payment of debt principal and interest, for minimum quarterly distributions during the next four quarters and to comply with applicable laws and the terms of any debt agreements or other agreement to which we are subject. The Board of Directors of our general partner reviews the level of Available Cash each quarter based upon information provided by management.

According to the terms of our Partnership Agreement, minimum quarterly distributions on the common units accrue at the rate of $0.0675 per quarter ($0.27 on an annual basis). The information concerning restrictions on distributions required by Item 5 of this report is incorporated by reference to Note 3. Quarterly Distribution of Available Cash, of the Partnership’s consolidated financial statements.

The revolving credit facility and the indenture for the notes both impose certain restrictions on our ability to pay distributions to unitholders. The most restrictive covenant is found in the Partnership’s revolving credit facility. Under the terms of our revolving credit facility, the Partnership must maintain Availability of $61.3 million, 17.5% of the maximum facility size of $350 million (assuming a seasonal advance of $100 million is outstanding) on a historical pro forma and forward-looking basis, and a fixed charge coverage ratio of not less than 1.15 in order to pay any distributions to unitholders or repurchase common units. (See Note 11 of the Notes to the Consolidated Financial Statements—Long-Term Debt and Bank Facility Borrowings).

On October 29, 2013, we declared a quarterly distribution of $0.0825 per unit, or $0.33 per unit on an annualized basis, on all common units in respect of the fourth quarter of fiscal 2013 payable on November 14, 2013 to holders of record on November 12, 2013. In accordance with our Partnership Agreement, the amount of distributions in excess of the minimum quarterly distribution of $0.0675, are distributed 90% to the holders of common units and 10% to the holders of the general partner units (until certain distribution levels are met), subject to the management incentive compensation plan. As a result, $4.7 million was paid to the common unit holders, $0.07 million to the general partner (including $0.05 million of incentive distributions) and $0.05 million to management pursuant to the management incentive compensation plan which provides for certain members of management to receive incentive distributions that would otherwise be payable to the general partner.

Common Unit Repurchase Plans and Retirement

Since July 21, 2009 (the start of the Plan I common units repurchase program) to November 30, 2013 (the current Plan III common units repurchase program in effect) the Partnership has repurchased and retired 18.3 million common units at an aggregate purchase price of $82.9 million or an average price of $4.53 per unit.

In fiscal 2010, the Partnership concluded its Plan I common units repurchase program and retired all 7.5 million common units authorized for repurchase at an average price paid of $4.04 per unit.

In fiscal 2012, the Partnership concluded its Plan II common units repurchase program and retired all 7.25 million common units authorized for repurchase at an average price paid of $4.94 per unit.

In July 2012, the Board authorized the repurchase of up to 3.0 million of the Partnership’s common units (“Plan III”). In July 2013, the Board authorized an additional 1.9 million common units to be repurchased under its Plan III common unit repurchase plan. The authorized common unit repurchases may be made from time-to-time in the open market, in privately negotiated transactions or in such other manner deemed appropriate by management. There is no guarantee of the exact number of units that will be purchased under the program and the Partnership may discontinue purchases at any time. The program does not have a time limit. In June 2013, the Board authorized the repurchase of 1.15 million additional common units in a private transaction. The Partnership’s repurchase activities take into account SEC safe harbor rules and guidance for issuer repurchases. All of the common units purchased in the repurchase program will be retired.

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

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(in thousands, except per unit amounts)

Period |  | Total Number of Units Purchased as Part of a Publicly Announced Plan or Program |  |  | Average Price Paid per Unit (a) |  |  | Maximum Number of Units that May Yet Be Purchased Under the Program |
Plan III — Number of units authorized |  |  |  |  |  |  |  |  |  |  | 4,894 |
Private transaction — Number of units authorized (b) |  |  |  |  |  |  |  |  |  |  | 1,150 |
|  |  |  |  |  |  |  |  |  |  | 6,044 |
Plan III — Fiscal year 2012 total |  |  | 22 |  |  | $ | 4.26 |  |  |  | 6,022 |
Plan III — First quarter fiscal year 2013 total |  |  | 1,015 |  |  | $ | 4.18 |  |  |  | 5,007 |
Plan III — Second quarter fiscal year 2013 total |  |  | 310 |  |  | $ | 4.36 |  |  |  | 4,697 |
Plan III — Third quarter fiscal year 2013 total (b) |  |  | 1,697 |  |  | $ | 4.92 |  |  |  | 3,000 |
Plan III — July 2013 |  |  | — |  |  | $ | — |  |  |  | 3,000 |
Plan III — August 2013 |  |  | 120 |  |  | $ | 4.87 |  |  |  | 2,880 |
Plan III — September 2013 |  |  | 142 |  |  | $ | 4.84 |  |  |  | 2,738 |
Plan III — Fourth quarter fiscal year 2013 total |  |  | 262 |  |  | $ | 4.85 |  |  |  | 2,738 |
Plan III — Fiscal year 2013 total |  |  | 3,284 |  |  | $ | 4.63 |  |  |  | 2,738 |
Plan III — October 2013 (c) |  |  | 250 |  |  | $ | 5.20 |  |  |  | 2,488 |
Plan III — November 2013 |  |  | — |  |  | $ | — |  |  |  | 2,488 |

(a) | Amounts include repurchase costs.

(b) | Third quarter fiscal 2013 common unit repurchases include 1.15 million common units acquired in a private transaction.

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

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ITEM 6. | SELECTED HISTORICAL FINANCIAL AND OPERATING DATA

The selected financial data as of September 30, 2013 and 2012, and for the years ended September 30, 2013, 2012 and 2011 is derived from the financial statements of the Partnership included elsewhere in this Report. The selected financial data as of September 30, 2011, 2010 and 2009 and for the years ended September 30, 2010 and 2009 is derived from financial statements of the Partnership not included in this Report. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

|  | Fiscal Years Ended September 30, |
(in thousands, except per unit data) |  | 2013 |  |  | 2012 |  |  | 2011 |  |  | 2010 |  |  | 2009 |
Statement of Operations Data: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Sales |  | $ | 1,741,796 |  |  | $ | 1,497,588 |  |  | $ | 1,591,310 |  |  | $ | 1,212,776 |  |  | $ | 1,206,813 |
Costs and expenses: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cost of sales |  |  | 1,388,668 |  |  |  | 1,199,811 |  |  |  | 1,237,341 |  |  |  | 904,047 |  |  |  | 875,755 |
(Increase) decrease in the fair value of derivative instruments |  |  | 6,775 |  |  |  | (8,549 | ) |  |  | 2,567 |  |  |  | (5,622 | ) |  |  | (13,690 | )
Delivery and branch expenses |  |  | 250,210 |  |  |  | 217,376 |  |  |  | 250,762 |  |  |  | 218,625 |  |  |  | 224,478 |
Depreciation and amortization expenses |  |  | 17,303 |  |  |  | 16,395 |  |  |  | 17,884 |  |  |  | 15,745 |  |  |  | 19,406 |
General and administrative expenses |  |  | 18,356 |  |  |  | 18,689 |  |  |  | 20,709 |  |  |  | 21,397 |  |  |  | 20,742 |
Finance charge income (a) |  |  | (5,521 | ) |  |  | (4,393 | ) |  |  | (4,814 | ) |  |  | (3,442 | ) |  |  | (3,731 | )
Operating income (a) |  |  | 66,005 |  |  |  | 58,259 |  |  |  | 66,861 |  |  |  | 62,026 |  |  |  | 83,853 |
Interest expense, net |  |  | 14,433 |  |  |  | 14,060 |  |  |  | 15,654 |  |  |  | 14,262 |  |  |  | 17,368 |
Amortization of debt issuance costs |  |  | 1,745 |  |  |  | 1,634 |  |  |  | 2,440 |  |  |  | 2,680 |  |  |  | 2,750 |
(Gain) loss on redemption of debt |  |  | — |  |  |  | — |  |  |  | 1,700 |  |  |  | 1,132 |  |  |  | (9,706 | )
Income before income taxes |  |  | 49,827 |  |  |  | 42,565 |  |  |  | 47,067 |  |  |  | 43,952 |  |  |  | 73,441 |
Income tax expense (benefit) |  |  | 19,921 |  |  |  | 16,576 |  |  |  | 22,723 |  |  |  | 15,632 |  |  |  | (57,597 | )
Net income |  | $ | 29,906 |  |  | $ | 25,989 |  |  | $ | 24,344 |  |  | $ | 28,320 |  |  | $ | 131,038 |
Weighted average number of limited partner units: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Basic and diluted |  |  | 59,409 |  |  |  | 61,931 |  |  |  | 66,822 |  |  |  | 70,019 |  |  |  | 75,738 |

|  | Fiscal Years Ended September 30, |
(in thousands, except per unit data) |  | 2013 |  |  | 2012 |  |  | 2011 |  |  | 2010 |  |  | 2009 |
Per Unit Data: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Basic and diluted net income per unit (b) |  | $ | 0.47 |  |  | $ | 0.40 |  |  | $ | 0.35 |  |  | $ | 0.38 |  |  | $ | 1.43 |
Cash distribution declared per common unit |  | $ | 0.320 |  |  | $ | 0.310 |  |  | $ | 0.305 |  |  | $ | 0.2850 |  |  | $ | 0.2025 |
Balance Sheet Data (end of period): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Current assets |  | $ | 305,880 |  |  | $ | 301,519 |  |  | $ | 303,775 |  |  | $ | 251,051 |  |  | $ | 380,380 |
Total assets |  | $ | 632,504 |  |  | $ | 639,347 |  |  | $ | 630,487 |  |  | $ | 586,696 |  |  | $ | 667,608 |
Long-term debt |  | $ | 124,460 |  |  | $ | 124,357 |  |  | $ | 124,263 |  |  | $ | 82,770 |  |  | $ | 133,112 |
Partners’ Capital |  | $ | 259,281 |  |  | $ | 260,145 |  |  | $ | 272,633 |  |  | $ | 279,911 |  |  | $ | 306,334 |
Summary Cash Flow Data: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net cash provided by operating activities |  | $ | 18,492 |  |  | $ | 105,828 |  |  | $ | 39,402 |  |  | $ | 44,429 |  |  | $ | 78,455 |
Net cash used in investing activities |  | $ | (6,960 | ) |  | $ | (44,517 | ) |  | $ | (15,928 | ) |  | $ | (73,956 | ) |  | $ | (7,568 | )
Net cash provided by (used in) financing activities |  | $ | (34,566 | ) |  | $ | (40,009 | ) |  | $ | 2,253 |  |  | $ | (104,571 | ) |  | $ | (54,535 | )
Other Data: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Earnings from continuing operations before net interest expense, income taxes, depreciation and amortization (EBITDA) (c) |  | $ | 83,308 |  |  | $ | 74,654 |  |  | $ | 83,045 |  |  | $ | 76,639 |  |  | $ | 112,965 |
Adjusted EBITDA (c) |  | $ | 90,083 |  |  | $ | 66,105 |  |  | $ | 87,312 |  |  | $ | 72,149 |  |  | $ | 89,569 |
Retail home heating oil and propane gallons sold |  |  | 324,797 |  |  |  | 277,204 |  |  |  | 355,569 |  |  |  | 310,323 |  |  |  | 351,630 |
Temperatures (warmer) colder than normal (d) |  |  | (4.1 | %) |  |  | (21.7 | %) |  |  | (0.4 | %) |  |  | (7.9 | %) |  |  | 1.3 | %

(a) | As a result of the reclassification of finance charge income, as described in Note 2 of the Consolidated Financial Statements - Summary of Significant Accounting Policies Reclassification, operating income, EBITDA and Adjusted EBITDA have been revised but net income has not changed.

(b) | Net income per unit is computed in accordance with FASB ASC 260-10-45-60 Earnings per Share, Master Limited Partnerships (EITF 03-06). See Note 17. Earnings Per Limited Partner Units, of the condensed consolidated financial statements.

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

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

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

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

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

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

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

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

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

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

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

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

EBITDA and Adjusted EBITDA are calculated for the fiscal years ended September 30 as follows:

(in thousands) |  | 2013 |  |  | 2012 |  |  | 2011 |  |  | 2010 |  |  | 2009 |
Net income |  | $ | 29,906 |  |  | $ | 25,989 |  |  | $ | 24,344 |  |  | $ | 28,320 |  |  | $ | 131,038 |
Plus: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Income tax expense (benefit) |  |  | 19,921 |  |  |  | 16,576 |  |  |  | 22,723 |  |  |  | 15,632 |  |  |  | (57,597 | )
Amortization of debt issuance cost |  |  | 1,745 |  |  |  | 1,634 |  |  |  | 2,440 |  |  |  | 2,680 |  |  |  | 2,750 |
Interest expense, net |  |  | 14,433 |  |  |  | 14,060 |  |  |  | 15,654 |  |  |  | 14,262 |  |  |  | 17,368 |
Depreciation and amortization |  |  | 17,303 |  |  |  | 16,395 |  |  |  | 17,884 |  |  |  | 15,745 |  |  |  | 19,406 |
EBITDA from continuing operations (a) |  |  | 83,308 |  |  |  | 74,654 |  |  |  | 83,045 |  |  |  | 76,639 |  |  |  | 112,965 |
(Increase)/decrease in the fair value of derivative instruments |  |  | 6,775 |  |  |  | (8,549 | ) |  |  | 2,567 |  |  |  | (5,622 | ) |  |  | (13,690 | )
(Gain) loss on redemption of debt |  |  | — |  |  |  | — |  |  |  | 1,700 |  |  |  | 1,132 |  |  |  | (9,706 | )
Adjusted EBITDA (a) |  |  | 90,083 |  |  |  | 66,105 |  |  |  | 87,312 |  |  |  | 72,149 |  |  |  | 89,569 |
Add/(subtract) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Income tax (expense) benefit |  |  | (19,921 | ) |  |  | (16,576 | ) |  |  | (22,723 | ) |  |  | (15,632 | ) |  |  | 57,597 |
Interest expense, net |  |  | (14,433 | ) |  |  | (14,060 | ) |  |  | (15,654 | ) |  |  | (14,262 | ) |  |  | (17,368 | )
Provision for losses on accounts receivable |  |  | 6,481 |  |  |  | 6,017 |  |  |  | 10,388 |  |  |  | 5,279 |  |  |  | 10,310 |
(Increase) decrease in accounts receivables |  |  | (14,074 | ) |  |  | 5,804 |  |  |  | (31,593 | ) |  |  | (4,570 | ) |  |  | 26,657 |
(Increase) decrease in inventories |  |  | (20,664 | ) |  |  | 34,335 |  |  |  | (13,189 | ) |  |  | (2,012 | ) |  |  | (17,747 | )
Increase (decrease) in customer credit balances |  |  | (15,878 | ) |  |  | 11,952 |  |  |  | (1,776 | ) |  |  | (9,250 | ) |  |  | (11,964 | )
Change in deferred taxes |  |  | 1,676 |  |  |  | 12,913 |  |  |  | 15,831 |  |  |  | 13,331 |  |  |  | (61,355 | )
Change in other operating assets and liabilities |  |  | 5,222 |  |  |  | (662 | ) |  |  | 10,806 |  |  |  | (604 | ) |  |  | 2,756 |
Net cash provided by operating activities |  | $ | 18,492 |  |  | $ | 105,828 |  |  | $ | 39,402 |  |  | $ | 44,429 |  |  | $ | 78,455 |
Net cash used in investing activities |  | $ | (6,960 | ) |  | $ | (44,517 | ) |  | $ | (15,928 | ) |  | $ | (73,956 | ) |  | $ | (7,568 | )
Net cash provided by (used in) financing activities |  | $ | (34,566 | ) |  | $ | (40,009 | ) |  | $ | 2,253 |  |  | $ | (104,571 | ) |  | $ | (54,535 | )

(d) | Temperatures (warmer) colder than normal are for those locations where the Partnership had existing operations, which we sometimes refer to as the “base business” (i.e. excluding acquisitions), temperatures (measured on a degree day basis) as reported by the National Oceanic and Atmospheric Administration (“NOAA”).

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ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Statement Regarding Forward-Looking Disclosure

This Annual Report on Form 10-K 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.

Overview

The following is a discussion of our historical financial condition and results of our operations and should be read in conjunction with the description of our business and the historical financial and operating data and notes thereto included elsewhere in this Report.

Seasonality

The following matters should be considered in analyzing our financial results. Our fiscal year ends on September 30. All references to quarters and years respectively in this document are to the fiscal quarters and years unless otherwise noted. The seasonal nature of our business has resulted, on average during the last five years, in the sale of approximately 30% of our volume of home heating oil and propane in the first fiscal quarter and 50% of our volume in the second fiscal quarter, the peak heating season. We generally realize net income in both of these quarters and net losses during the quarters ending June and September. In addition, sales volume typically fluctuates from year to year in response to variations in weather, wholesale energy prices and other factors.

Degree Day

A “degree day” is an industry measurement of temperature designed to evaluate energy demand and consumption. Degree days are based on how far the average daily temperature departs from 65°F. Each degree of temperature above 65°F is counted as one cooling degree day, and each degree of temperature below 65°F is counted as one heating degree day. Degree days are accumulated each day over the course of a year and can be compared to a monthly or a long-term (multi-year) average to see if a month or a year was warmer or cooler than usual. Degree days are officially observed by the National Weather Service.

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

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Home Heating Oil Price Volatility

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

|  | Fiscal 2013 (1) |  |  | Fiscal 2012 |  |  | Fiscal 2011 |  |  | Fiscal 2010 |  |  | Fiscal 2009 |
Quarter Ended |  | Low |  |  | High |  |  | Low |  |  | High |  |  | Low |  |  | High |  |  | Low |  |  | High |  |  | Low |  |  | High |
December 31 |  | $ | 2.90 |  |  | $ | 3.26 |  |  | $ | 2.72 |  |  | $ | 3.17 |  |  | $ | 2.19 |  |  | $ | 2.54 |  |  | $ | 1.78 |  |  | $ | 2.12 |  |  | $ | 1.20 |  |  | $ | 2.85 |
March 31 |  |  | 2.86 |  |  |  | 3.24 |  |  |  | 2.99 |  |  |  | 3.32 |  |  |  | 2.49 |  |  |  | 3.09 |  |  |  | 1.89 |  |  |  | 2.20 |  |  |  | 1.13 |  |  |  | 1.63 |
June 30 |  |  | 2.74 |  |  |  | 3.09 |  |  |  | 2.53 |  |  |  | 3.25 |  |  |  | 2.75 |  |  |  | 3.32 |  |  |  | 1.87 |  |  |  | 2.35 |  |  |  | 1.31 |  |  |  | 1.86 |
September 30 |  |  | 2.87 |  |  |  | 3.21 |  |  |  | 2.68 |  |  |  | 3.24 |  |  |  | 2.77 |  |  |  | 3.13 |  |  |  | 1.92 |  |  |  | 2.24 |  |  |  | 1.50 |  |  |  | 1.96 |

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

Impact on Liquidity of Wholesale Product Cost Volatility

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

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

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

Weather Hedge Contract—Fiscal Years 2013, 2014 and 2015

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

Per Gallon Gross Profit Margins

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

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

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Derivatives

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

New York State Ultra Low Sulfur Fuel Oil Regulation

On July 1, 2012, new regulations went into effect in New York State (an important area of operations for us) that require the use of ultra low sulfur home heating oil (which is essentially ultra low sulfur diesel fuel with a dye additive). From July 1, 2012 through March 31, 2013, the additional cost of ultra low sulfur home heating oil versus high sulfur home heating oil in New York ranged from $0.035 and $0.230 cents per gallon. The NYMEX continued to trade only the high sulfur home heating oil hedge contract through March 31, 2013. Effective as of April 1, 2013, the NYMEX contract specifications were changed from high sulfur home heating oil to ultra low sulfur diesel, similar to the New York mandate for home heating oil. Consequently, there was a nine month period, from July 2012 through March 2013, when the Partnership needed to purchase and sell ultra low sulfur home heating oil for its New York State customers while a contract was not directly available to hedge on the NYMEX. The Partnership hedged the purchases of ultra low sulfur home heating oil from July 1, 2012 to March 31, 2013, utilizing a NYMEX high sulfur home heating oil contract. Furthermore, due to the change in the specifications of the NYMEX contract in April 2013, the Partnership now has a similar mis-match from April 2013 going forward in its ability to hedge high sulfur home heating oil requirements for purchases and sales in states other than New York. The Partnership has hedged its purchases of high sulfur home heating oil since April 1, 2013, with the new NYMEX ultra low sulfur diesel contracts. From April 1 to September 30, 2013, high sulfur home heating oil was sold at a discount to the NYMEX ultra low sulfur diesel contract of between $0.065 and $0.250 cents per gallon.

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

Income Taxes

Net Operating Loss Carry Forwards

The Partnership and its corporate subsidiaries file Federal and State income tax returns on a calendar year. As of December 31, 2012, our Federal Net Operating Loss carry forwards (“NOLs”) were $10.6 million, subject to annual limitations of between $1.0 million and $2.2 million on the amount of such losses that can be used.

Book Versus Tax Deductions

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

Estimated Depreciation and Amortization Expense

(in thousands) |  |  |  |  |  |
Fiscal Year |  | Book |  |  | Tax |
2013 |  | $ | 19,047 |  |  |  | 33,532 |
2014 |  |  | 18,376 |  |  |  | 29,172 |
2015 |  |  | 16,837 |  |  |  | 25,174 |
2016 |  |  | 14,721 |  |  |  | 19,097 |
2017 |  |  | 12,319 |  |  |  | 11,757 |
2018 |  |  | 10,201 |  |  |  | 8,374 |

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Non-Deductible Partnership Expenses

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

Storm Sandy

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

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

EBITDA and Adjusted EBITDA (non-GAAP financial measures)

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

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

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

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

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

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

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

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

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

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

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

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

Customer Attrition

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

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Gross customer gains and gross customer losses

|  | Fiscal Year Ended |
|  | 2013 |  |  | 2012 |  |  | 2011 |
|  | Gross Customer |  |  | Net |  |  | Gross Customer |  |  | Net |  |  | Gross Customer |  |  | Net |
|  | Gains |  |  | Losses |  |  | Attrition |  |  | Gains |  |  | Losses |  |  | Attrition |  |  | Gains |  |  | Losses |  |  | Attrition |
First Quarter |  |  | 26,100 |  |  |  | 24,400 |  |  |  | 1,700 |  |  |  | 25,700 |  |  |  | 26,600 |  |  |  | (900 | ) |  |  | 21,900 |  |  |  | 24,100 |  |  |  | (2,200 | )
Second Quarter |  |  | 13,900 |  |  |  | 19,300 |  |  |  | (5,400 | ) |  |  | 11,500 |  |  |  | 19,700 |  |  |  | (8,200 | ) |  |  | 11,800 |  |  |  | 17,200 |  |  |  | (5,400 | )
Third Quarter |  |  | 7,100 |  |  |  | 13,600 |  |  |  | (6,500 | ) |  |  | 7,000 |  |  |  | 13,700 |  |  |  | (6,700 | ) |  |  | 6,000 |  |  |  | 11,400 |  |  |  | (5,400 | )
Fourth Quarter |  |  | 14,400 |  |  |  | 18,000 |  |  |  | (3,600 | ) |  |  | 13,000 |  |  |  | 18,200 |  |  |  | (5,200 | ) |  |  | 15,300 |  |  |  | 17,100 |  |  |  | (1,800 | )
Total |  |  | 61,500 |  |  |  | 75,300 |  |  |  | (13,800 | ) |  |  | 57,200 |  |  |  | 78,200 |  |  |  | (21,000 | ) |  |  | 55,000 |  |  |  | 69,800 |  |  |  | (14,800 | )

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

|  | Fiscal Year Ended |
|  | 2013 |  |  | 2012 |  |  | 2011 |
|  | Gross Customer |  |  | Net |  |  | Gross Customer |  |  | Net |  |  | Gross Customer |  |  | Net |
|  | Gains |  |  | Losses |  |  | Attrition |  |  | Gains |  |  | Losses |  |  | Attrition |  |  | Gains |  |  | Losses |  |  | Attrition |
First Quarter |  |  | 6.3 | % |  |  | 5.9 | % |  |  | 0.4 | % |  |  | 6.2 | % |  |  | 6.4 | % |  |  | (0.2 | %) |  |  | 5.3 | % |  |  | 5.8 | % |  |  | (0.5 | %)
Second Quarter |  |  | 3.3 | % |  |  | 4.6 | % |  |  | (1.3 | %) |  |  | 2.7 | % |  |  | 4.7 | % |  |  | (2.0 | %) |  |  | 2.8 | % |  |  | 4.1 | % |  |  | (1.3 | %)
Third Quarter |  |  | 1.7 | % |  |  | 3.3 | % |  |  | (1.6 | %) |  |  | 1.5 | % |  |  | 3.1 | % |  |  | (1.6 | %) |  |  | 1.5 | % |  |  | 2.8 | % |  |  | (1.3 | %)
Fourth Quarter |  |  | 3.5 | % |  |  | 4.3 | % |  |  | (0.8 | %) |  |  | 3.0 | % |  |  | 4.1 | % |  |  | (1.1 | %) |  |  | 3.6 | % |  |  | 4.0 | % |  |  | (0.4 | %)
Total |  |  | 14.8 | % |  |  | 18.1 | % |  |  | (3.3 | %) |  |  | 13.4 | % |  |  | 18.3 | % |  |  | (4.9 | %) |  |  | 13.2 | % |  |  | 16.7 | % |  |  | (3.5 | %)

During fiscal 2013, the Partnership lost 13,800 accounts (net), or 3.3%, of our home heating oil and propane customer base, compared to the loss of 21,000 accounts (net), or 4.9% of our home heating oil and propane customer base during fiscal 2012. The improvement of 7,200 accounts was due to an increase in gross customer gains of 4,300 and lower gross customer losses of 2,900. The increase in gains can be attributed to an increase in referrals as well as marketing and advertising related activity. The decrease in losses was mainly due to fewer credit cancellations and price-related losses.

During fiscal 2013, we lost 2.4% of our home heating oil accounts to natural gas conversions versus losses of 2.0% for fiscal 2012, and 1.5% for fiscal 2011. Conversions to natural gas have been increasing, and we believe this may continue as natural gas has become significantly less expensive than home heating oil on an equivalent BTU basis. In addition, the states of New York, Connecticut and Pennsylvania are seeking to encourage homeowners to expand the use of natural gas as a heating fuel through legislation and regulatory efforts.

Consolidated Results of Operations

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

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Fiscal Year Ended September 30, 2013

Compared to the Fiscal Year Ended September 30, 2012

Volume

For fiscal 2013, retail volume of home heating oil and propane increased by 47.6 million gallons, or 17.2%, to 324.8 million gallons, compared to 277.2 million gallons for fiscal 2012. For those locations where the Partnership had existing operations during both periods, which are sometimes referred to as the “base business” (i.e., excluding acquisitions), temperatures (measured on a heating degree day basis) for fiscal 2013, were 22.3% colder than fiscal 2012, but 4.1% warmer than normal, as reported by the National Oceanic and Atmospheric Administration (“NOAA”). For the twelve months ended September 30, 2013, net customer attrition for the base business was 3.3%. Due to various reasons including the significant increase in the price per gallon of home heating oil and propane over the last several years, we believe that our customers are adopting conservation measures to use less product. The impact of conservation, along with any period-to-period differences in delivery scheduling, the timing of accounts added or lost during the fiscal years, equipment efficiency and other volume variances not otherwise described, are included in the chart below under the heading “Other.” In addition, on October 29, 2012, the storm Sandy made landfall in our service area, resulting in widespread power outages that affected a number of our customers. Deliveries of home heating oil and propane were less than expected for certain of our customers who were without power for several weeks subsequent to this storm. The home heating oil and propane volume loss due to Sandy is also in the chart below under the heading “Other.” An analysis of the change in the retail volume of home heating oil and propane, which is based on management’s estimates, sampling and other mathematical calculations and certain assumptions, is as follows:

(in millions of gallons) |  | Heating Oil and Propane |
Volume—Fiscal 2012 |  |  | 277.2 |
Acquisitions |  |  | 13.4 |
Impact of colder temperatures |  |  | 54.3 |
Net customer attrition |  |  | (10.1 | )
Other |  |  | (10.0 | )
Change |  |  | 47.6 |
Volume—Fiscal 2013 |  |  | 324.8 |

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 fiscal 2013, compared to fiscal 2012:

|  | Fiscal Year |
Customers |  | 2013 |  |  | 2012 |
Residential Variable |  |  | 41.6 | % |  |  | 42.5 | %
Residential Price-Protected |  |  | 44.3 | % |  |  | 44.3 | %
Commercial/Industrial |  |  | 14.1 | % |  |  | 13.2 | %
Total |  |  | 100.0 | % |  |  | 100.0 | %

Volume of other petroleum products increased by 6.0 million gallons, or 11.3%, to 59.2 million gallons for fiscal 2013, compared to 53.2 million gallons for fiscal 2012, largely due to an increase in motor fuel demand as a result of the storm Sandy (including to power generators) and higher home heating oil wholesale sales.

Product Sales

For fiscal 2013, product sales increased $0.2 billion, or 17.2%, to $1.5 billion, compared to $1.3 billion for fiscal 2012, primarily due to an increase in total volume of 16.2%.

Installation and Service Sales

For fiscal 2013, installation and service sales increased $20.8 million, or 10.3%, to $223.0 million, compared to $202.2 million for fiscal 2012, due to additional revenue from acquisitions of $5.6 million and an increase in the base business of $15.2 million largely attributable to Sandy-related service and installation billings and the additional billings associated with 22.3% colder temperatures.

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Cost of Product

For fiscal 2013, cost of product increased $0.2 billion, or 16.4%, to $1.2 billion, compared to $1.0 billion for fiscal 2012, largely due to an increase in total volume of 16.2%.

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 fiscal 2013, increased by $0.0234 per gallon, or 2.5%, to $0.9536 per gallon, from $0.9302 per gallon during fiscal 2012. Product sales and cost of product include home heating oil, propane, other petroleum products and liquidated damages billings.

|  | Twelve Months Ended |
|  | September 30, 2013 |  |  | September 30, 2012 |
|  | Amount (in millions) |  |  | Per Gallon |  |  | Amount (in millions) |  |  | Per Gallon |
Home Heating Oil and Propane |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Volume |  |  | 324.8 |  |  |  |  |  |  |  | 277.2 |  |  |  |  |
Sales |  | $ | 1,315.9 |  |  | $ | 4.0515 |  |  | $ | 1,115.6 |  |  | $ | 4.0246 |
Cost |  | $ | 1,006.2 |  |  | $ | 3.0979 |  |  | $ | 857.8 |  |  | $ | 3.0944 |
Gross Profit |  | $ | 309.7 |  |  | $ | 0.9536 |  |  | $ | 257.9 |  |  | $ | 0.9302 |
|  | Amount (in millions) |  |  | Per Gallon |  |  | Amount (in millions) |  |  | Per Gallon |
Other Petroleum Products |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Volume |  |  | 59.2 |  |  |  |  |  |  |  | 53.2 |  |  |  |  |
Sales |  | $ | 202.8 |  |  | $ | 3.4274 |  |  | $ | 179.8 |  |  | $ | 3.3822 |
Cost |  | $ | 185.8 |  |  | $ | 3.1400 |  |  | $ | 166.3 |  |  | $ | 3.1285 |
Gross Profit |  | $ | 17.0 |  |  | $ | 0.2875 |  |  | $ | 13.5 |  |  | $ | 0.2537 |
|  | Amount (in millions) |  |  |  |  |  | Amount (in millions) |  |  |  |
Total Product |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Sales |  | $ | 1,518.7 |  |  |  |  |  |  | $ | 1,295.4 |  |  |  |  |
Cost |  | $ | 1,192.0 |  |  |  |  |  |  | $ | 1,024.1 |  |  |  |  |
Gross Profit |  | $ | 326.7 |  |  |  |  |  |  | $ | 271.3 |  |  |  |  |

For fiscal 2013, total product gross profit increased by $55.4 million to $326.7 million, compared to $271.3 million for fiscal 2012, due to an increase in home heating oil and propane volume ($44.3 million), the impact of higher home heating oil and propane margins ($7.6 million) and the additional gross profit from other petroleum products ($3.5 million).

Cost of Installations and Service

For fiscal 2013, cost of installation and service increased by $20.9 million, or 11.9%, to $196.6 million, compared to $175.7 million for fiscal 2012, due to a $4.8 million increase related to acquisitions and an $16.1 million increase tied to our base business largely due to the storm Sandy and the additional service costs associated with 22.3% colder temperatures.

Installation costs for fiscal 2013, increased by $10.8 million, or 17.8%, to $71.6 million, compared to $60.8 million in installation costs for fiscal 2012. Installation costs as a percentage of installation sales for fiscal 2013, and fiscal 2012, were 84.1% and 84.6%, respectively. Service expenses increased to $125.1 million for fiscal 2013, or 90.7%, of service sales, versus $115.0 million, or 88.2% of service sales, for fiscal 2012. We achieved a combined profit from service and installation of $26.4 million for fiscal 2013, compared to a combined profit of $26.5 million for fiscal 2012. Management views the service and installation department on a combined basis because many overhead functions and direct expenses such as service technician time cannot be separated or precisely allocated to either service or installation billings.

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(Increase) / Decrease in the Fair Value of Derivative Instruments

During fiscal 2013, the change in the fair value of derivative instruments resulted in a $6.8 million charge due to the expiration of certain hedged positions (a $1.1 million charge) and a decrease in the market value for unexpired hedges (a $5.7 million charge).

During fiscal 2012, the change in the fair value of derivative instruments resulted in a $8.5 million credit due to the expiration of certain hedged positions (a $7.4 million credit) a decrease in market value for unexpired (a $1.1 million credit).

Delivery and Branch Expenses

For fiscal 2013, delivery and branch expense increased $32.8 million, or 15.1%, to $250.2 million, compared to $217.4 million for fiscal 2012, due to an increase in the base business expenses of $13.0 million largely due to the additional volume sold, the additional expense from acquisitions of $7.2 million and the absence of a weather hedge benefit of $12.5 million. During fiscal 2012, the Partnership recorded a benefit of $12.5 million under its warm weather hedge which reduced delivery and branch expenses with no similar benefit recorded in fiscal 2013.

On a cents per gallon basis (excluding the credit recorded under the Partnership’s weather hedge contract during fiscal 2012), delivery and branch expenses for fiscal 2013, decreased $0.0395, or 5.5%, to $0.6733 compared to $0.7128 per gallon for fiscal 2012, as certain fixed operating expenses were spread over a larger volume base in fiscal 2013.

Depreciation and Amortization

For fiscal 2013, depreciation and amortization expenses increased by $0.9 million, or 5.5%, to $17.3 million, compared to $16.4 million for fiscal 2012.

Depreciation expense remained the same as an increase of $1.2 million from fiscal 2012 and fiscal 2013 acquisitions was offset by a decrease of $1.2 million related to fleet and equipment assets which became fully depreciated in fiscal 2012 and fiscal 2013. Amortization expense increased by $0.9 million, due to fiscal 2012 and fiscal 2013 customer lists acquired.

General and Administrative Expenses

For fiscal 2013, general and administrative expenses decreased $0.3 million, or 1.8%, to $18.4 million, from $18.7 million for fiscal 2012, as lower legal and professional, acquisition and other expenses of $2.2 million were offset by an increase in profit sharing expense of $1.9 million.

The Partnership accrues approximately 6.0% of Adjusted EBITDA as defined in its 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 fiscal 2013, finance charge income increased $1.1 million to $5.5 million, compared to $4.4 million for fiscal 2012. In late fiscal 2012, the Partnership shortened the time period before billing finance charges which drove this increase.

Interest Expense, Net

For fiscal 2013, net interest expense increased $0.3 million, or 2.7%, to $14.4 million compared to the $14.1 million for fiscal 2012 largely due to an increase in average working capital borrowings of $5.9 million.

Amortization of Debt Issuance Costs

For fiscal 2013, amortization of debt issuance costs increased by $0.1 million to $1.7 million, compared to $1.6 million for fiscal 2012.

Income Tax Expense

For fiscal 2013, income tax expense increased by $3.3 million to $19.9 million from $16.6 million for fiscal 2012, due to the increase in pretax income of $7.3 million.

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Net Income

For fiscal 2013, net income increased $3.9 million to $29.9 million, from $26.0 million for fiscal 2012, as the increase in pretax income of $7.3 million was greater than the increase in income tax expense of $3.3 million.

Adjusted EBITDA

For fiscal 2013, Adjusted EBITDA increased by $24.0 million, or 36.3%, to $90.1 million as the impact of 22.3% colder temperatures, higher home heating oil and propane per gallon margins, acquisitions, and the favorable impact of the storm Sandy on motor fuel sales and service and installation revenue more than offset the volume decline in the base business attributable to net customer attrition and other factors. Adjusted EBITDA for fiscal 2012, included a $12.5 million benefit that the Partnership recorded under its weather hedge contract due to the abnormally warm weather in that period, with no similar benefit recorded during fiscal 2013.

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 pay distributions.

EBITDA and Adjusted EBITDA are calculated as follows:

|  | Fiscal Year Ended September 30, |
(in thousands) |  | 2013 |  |  | 2012 |
Income from continuing operations |  | $ | 29,906 |  |  | $ | 25,989 |
Plus: |  |  |  |  |  |  |  |
Income tax expense |  |  | 19,921 |  |  |  | 16,576 |
Amortization of debt issuance cost |  |  | 1,745 |  |  |  | 1,634 |
Interest expense, net |  |  | 14,433 |  |  |  | 14,060 |
Depreciation and amortization |  |  | 17,303 |  |  |  | 16,395 |
EBITDA (a) (b) from continuing operations |  |  | 83,308 |  |  |  | 74,654 |
(Increase) / decrease in the fair value of derivative instruments |  |  | 6,775 |  |  |  | (8,549 | )
Adjusted EBITDA (a) (b) |  |  | 90,083 |  |  |  | 66,105 |
Add / (subtract) |  |  |  |  |  |  |  |
Income tax expense |  |  | (19,921 | ) |  |  | (16,576 | )
Interest expense, net |  |  | (14,433 | ) |  |  | (14,060 | )
Provision for losses on accounts receivable |  |  | 6,481 |  |  |  | 6,017 |
(Increase) decrease in accounts receivables |  |  | (14,074 | ) |  |  | 5,804 |
(Increase) decrease in inventories |  |  | (20,664 | ) |  |  | 34,335 |
Increase (decrease) in customer credit balances |  |  | (15,878 | ) |  |  | 11,952 |
Change in deferred taxes |  |  | 1,676 |  |  |  | 12,913 |
Change in other operating assets and liabilities |  |  | 5,222 |  |  |  | (662 | )
Net cash provided by operating activities |  | $ | 18,492 |  |  | $ | 105,828 |
Net cash used in investing activities |  | $ | (6,960 | ) |  | $ | (44,517 | )
Net cash provided by (used in) financing activities |  | $ | (34,566 | ) |  | $ | (40,009 | )

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

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

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

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

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

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

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

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

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

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

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

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

(b) | As a result of the reclassification of finance charge income, as described in Note 2 of the Consolidated Financial Statements - Summary of Significant Accounting Policies Reclassification, operating income, EBITDA and Adjusted EBITDA have been revised but net income has not changed.

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Fiscal Year Ended September 30, 2012

Compared to the Fiscal Year Ended September 30, 2011

Volume

For fiscal 2012, retail volume of home heating oil and propane decreased by 78.4 million gallons, or 22.0%, to 277.2 million gallons, compared to 355.6 million gallons for fiscal 2011. For those locations where the Partnership had existing operations during both periods, which are sometimes referred to as the “base business” (i.e., excluding acquisitions), temperatures (measured on a heating degree day basis) for fiscal 2012 were 21.4% warmer than fiscal 2011 and 21.7% warmer than normal, as reported by the National Oceanic and Atmospheric Administration (“NOAA”). In the New York City Metropolitan Area, which is an important area of operations for us, fiscal 2012 was the warmest period in the last 112 years and was 3.7% warmer than the next warmest comparable period. For fiscal 2012, net customer attrition for the base business was 5.4%. Due to various reasons including the significant increase in the price per gallon of home heating oil and propane over the last several years, we believe that some of our customers have been adopting conservation measures to use less of such products. The impact of any such conservation, along with any period-to-period differences in delivery scheduling, equipment efficiency and other volume variances not otherwise described, are included in the chart under the heading “Other.” We believe the unseasonably warm weather for fiscal 2012 generally magnified the conditions and opportunities for conservation. The timing of accounts added or lost during the fiscal year could also impact the fiscal year comparison. 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—Fiscal 2011 |  |  | 355.6 |
Acquisitions |  |  | 14.3 |
Impact of warmer temperatures |  |  | (67.8 | )
Net customer attrition |  |  | (21.3 | )
Other |  |  | (3.6 | )
Change |  |  | (78.4 | )
Volume—Fiscal 2012 |  |  | 277.2 |

Volume of other petroleum products increased by 10.1 million gallons, or 23.4%, to 53.2 million gallons for fiscal 2012, compared to 43.1 million gallons for fiscal 2011, as the additional volume from acquisitions was partially offset by a decline in the base business primarily due to the warmer temperatures.

The following chart sets forth the percentage by volume of total home heating oil sold to residential variable-price customers, residential price-protected customers and commercial/industrial customers for fiscal 2012, compared to fiscal 2011:

|  | Fiscal Year |
Customers |  | 2012 |  |  | 2011 |
Residential Variable |  |  | 42.5 | % |  |  | 43.6 | %
Residential Price-Protected |  |  | 44.3 | % |  |  | 43.7 | %
Commercial/Industrial |  |  | 13.2 | % |  |  | 12.7 | %
Total |  |  | 100.0 | % |  |  | 100.0 | %

Product Sales

For fiscal 2012, product sales decreased $0.1 billion, or 7.0%, to $1.3 billion, compared to $1.4 billion for fiscal 2011, as the decline in total volume of 17.1% exceeded the impact of higher product selling prices. Selling prices increased in response to higher wholesale product costs of $0.4465 per gallon.

Installation and Service Sales

For fiscal 2012, installation and service sales increased $3.8 million, or 1.9%, to $202.2 million, compared to $198.4 million for fiscal 2011, as the additional revenue from acquisitions of $9.3 million was partially offset by a decline in the base business of $5.5 million, largely due to net customer attrition.

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Cost of Product

For fiscal 2012, cost of product decreased $33.7 million, or 3.2%, to $1.024 billion, compared to $1.058 billion for fiscal 2011, as the reduction in total volume of 17.1% more than offset the impact of higher per gallon wholesale product costs of $0.4465, or 16.8%.

Gross Profit—Product

The table below calculates the Partnership’s per gallon margins and reconciles product gross profit for home heating oil and propane and other petroleum products. We believe the change in home heating oil and propane margins should be evaluated before the effects of increases or decreases in the fair value of derivative instruments, as we believe that realized per gallon margins should not include the impact of non-cash changes in the market value of hedges before the settlement of the underlying transaction. On that basis, home heating oil and propane margins for fiscal 2012 increased by $0.0180 per gallon, or 2.0%, to $0.9302 per gallon, from $0.9122 per gallon during fiscal 2011. Product sales and cost of product include home heating oil, propane, other petroleum products and liquidated damages billings.

|  | Fiscal Year Ended |
|  | September 30, 2012 |  |  | September 30, 2011 |
|  | Amount (in millions) |  |  | Per Gallon |  |  | Amount (in millions) |  |  | Per Gallon |
Home Heating Oil and Propane |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Volume |  |  | 277.2 |  |  |  |  |  |  |  | 355.6 |  |  |  |  |
Sales |  | $ | 1,115.6 |  |  | $ | 4.0246 |  |  | $ | 1,258.0 |  |  | $ | 3.5379 |
Cost |  | $ | 857.8 |  |  | $ | 3.0944 |  |  | $ | 933.6 |  |  | $ | 2.6257 |
Gross Profit |  | $ | 257.9 |  |  | $ | 0.9302 |  |  | $ | 324.4 |  |  | $ | 0.9122 |
|  | Amount (in millions) |  |  | Per Gallon |  |  | Amount (in millions) |  |  | Per Gallon |
Other Petroleum Products |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Volume |  |  | 53.2 |  |  |  |  |  |  |  | 43.1 |  |  |  |  |
Sales |  | $ | 179.8 |  |  | $ | 3.3822 |  |  | $ | 134.9 |  |  | $ | 3.1314 |
Cost |  | $ | 166.3 |  |  | $ | 3.1285 |  |  | $ | 124.2 |  |  | $ | 2.8821 |
Gross Profit |  | $ | 13.5 |  |  | $ | 0.2537 |  |  | $ | 10.7 |  |  | $ | 0.2493 |
|  | Amount (in millions) |  |  |  |  |  | Amount (in millions) |  |  |  |
Total Product |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Sales |  | $ | 1,295.4 |  |  |  |  |  |  | $ | 1,392.9 |  |  |  |  |
Cost |  | $ | 1,024.1 |  |  |  |  |  |  | $ | 1,057.8 |  |  |  |  |
Gross Profit |  | $ | 271.3 |  |  |  |  |  |  | $ | 335.1 |  |  |  |  |

For fiscal 2012, total product gross profit decreased by $63.7 million to $271.4 million, compared to $335.1 million for fiscal 2011, as the impact of higher home heating oil and propane margins ($5.0 million) and the additional gross profit from other petroleum products ($2.8 million) was more than offset by a reduction in gross profit resulting from lower home heating oil and propane volume ($71.5 million). Product cost increased by $0.4465 per gallon, or 16.8% in fiscal 2012 versus fiscal 2011. If wholesale product costs continue to escalate, our ability to maintain and/or expand margins may be diminished and our profitability may be adversely impacted.

Cost of Installations and Service

For fiscal 2012, cost of installation and service decreased by $3.8 million, or 2.1%, to $175.7 million, compared to $179.6 million for fiscal 2011, as a $7.8 million increase due to fiscal 2012 and fiscal 2011 acquisitions was more than offset by a $11.6 million reduction in service costs and installation costs in our base business. Net customer attrition, the impact of 21.4 % warmer weather and the Partnership’s efforts at reducing operating costs were the principal causes of this change.

Installation costs for fiscal 2012 increased by $1.0 million, or 1.7%, to $60.8 million, compared to $59.8 million in installation costs for fiscal 2011. Installation costs as a percentage of installation sales for fiscal 2012 and fiscal 2011 were 84.6% and 85.0%, respectively. Service expenses declined to $115.0 million for fiscal 2012, or 88.2%, of service sales, versus $119.8 million, or 93.5% of service sales for fiscal 2011. We achieved a combined profit from service and installation of $26.5 million for fiscal 2012, compared to a combined profit of $18.9 million for fiscal 2011 primarily due to a reduction in service expenses in the base business. 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.

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(Increase) Decrease in the Fair Value of Derivative Instruments

During fiscal 2012, the change in the fair value of derivative instruments resulted in a $8.5 million credit due to the expiration of certain hedged positions (a $7.4 million credit) and an increase in the market value for unexpired hedges (a $1.1 million credit).

During fiscal 2011, the change in the fair value of derivative instruments resulted in a $2.6 million charge due to the expiration of certain hedged positions (a $4.9 million credit) and a decrease in market value for unexpired hedges (a $7.5 million charge).

Delivery and Branch Expenses

For fiscal 2012, delivery and branch expenses decreased $33.4 million, or 13.3%, to $217.4 million, compared to $250.8 million for fiscal 2011, as the additional expense from acquisitions of $12.9 million was more than offset by a $12.5 million credit recorded under the Partnership’s weather hedge contract along with lower delivery and branch expenses of $33.8 million related to the decline in home heating oil and propane volume in the base business, lower insurance expense and lower bad debt expense. In addition, in response to the warmer weather in the fiscal 2012 heating season, management reduced expenses wherever possible.

On a cents per gallon basis (excluding the credit recorded under the Partnership’s weather hedge contract), delivery and branch expenses for fiscal 2012 increased $0.0646, or 10.0%, to $0.7128 per gallon, compared to $0.6482 per gallon for fiscal 2011 due to the fixed nature of certain operating expenses, which could not be reduced in the near term to match the weather-related decline in home heating oil and propane volume. In addition, certain costs such as vehicle fuels and credit card processing fees rose on a per gallon basis due to the increase in cost of home heating oil and petroleum products.

Depreciation and Amortization

For fiscal 2012, depreciation and amortization expenses decreased by $1.5 million, or 8.3% to $16.4 million, compared to $17.9 million for fiscal 2011.

Depreciation expense was higher by $0.8 million due to an increase of $1.2 million from fiscal 2011 and fiscal 2012 acquisitions. The increase was partially offset by a decrease of $0.4 million related to fleet assets which became fully depreciated in fiscal 2011 and fiscal 2012. Amortization expense relating to fiscal 2001 and 2004 acquisitions with lives of ten years or seven years, decreased by $4.4 million, as they became fully amortized in fiscal 2012. This decline was partially offset by an increase of $2.1 million relating to fiscal 2012 and 2011 acquisitions of customer lists with seven and ten year lives and trade names acquired with twenty year lives.

General and Administrative Expenses

For fiscal 2012, general and administrative expenses decreased $2.0 million, or 9.8%, to $18.7 million, from $20.7 million for fiscal 2011, as an increase in expenses related to the Partnership’s acquisition program of $0.4 million was more than offset by a decline in profit sharing expense of $1.6 million.

The Partnership accrues approximately 6% of adjusted EBITDA as defined in its 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 fiscal 2012, finance charge income decreased $0.4 million to $4.4 million, compared to $4.8 million for fiscal 2011, due to lower past due accounts receivable balances.

Interest Expense, Net

For fiscal 2012, net interest expense decreased by $1.6 million, or 10.2%, to $14.1 million, compared to $15.7 million during fiscal 2011 largely due to lower bank fees of $1.0 million resulting from lower rates on letters of credit and lower unused commitment fees. Average long-term debt decreased by $2.7 million, and the weighted average long-term borrowing rate decreased from 9.1% to 8.9%, which resulted in a decrease in interest expense of $0.5 million. In November 2010, the Partnership issued $125 million of 8.875% Senior Notes due 2017 and, in December 2010, repaid $82.5 million of 10.25% Senior Notes due 2013. During fiscal 2012, the Partnership borrowed an average of $16.3 million under its revolving credit facility, $0.9 million higher than fiscal 2011, but interest expense decreased $0.1 million as the interest rate on these borrowings declined from 4.3% to 3.2%.

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Amortization of Debt Issuance Costs

For fiscal 2012, amortization of debt issuance costs decreased by $0.8 million to $1.6 million, compared to $2.4 million in fiscal 2011. This reduction was due to an increase in the number of years over which such costs are being amortized due to the extension in June 2011 of the Partnership’s revolving credit facility termination date from July 2012 to June 2016.

Loss on Redemption of Debt

In November 2010, the Partnership issued $125.0 million of Senior Notes due 2017. The Notes accrue interest at a rate of 8.875% and were priced at 99.350% for total gross proceeds of $124.2 million. A portion of the proceeds were used to redeem all of the remaining $82.5 million in face value of our 10.25% Senior Notes due 2013, at an average price of $101.70 per $100 of principal plus accrued interest, with the remainder used for general Partnership purposes. The Partnership recorded a loss of $1.7 million for this transaction in fiscal 2011. There was no similar transaction in fiscal 2012.

Income Tax Expense

For fiscal 2012, income tax expense decreased by $6.1 million to $16.6 million from $22.7 million for fiscal 2011 primarily due to a decline in pretax income of $4.5 million and the recognition in 2012 of previously unrecognized tax benefits. The Partnership’s effective tax rate was 38.9% for fiscal 2012, less than the rate of 48.3% for fiscal 2011, primarily due to the recognition in June 2012 of the aforementioned tax benefits and the $2.7 million reduction in expenses at the partnership level in 2012 compared to 2011 that are not deductible on our corporate tax returns.

Net Income

For fiscal 2012, net income increased $1.7 million to $26.0 million, from $24.3 million for fiscal 2011, as the decrease in pretax income of $4.5 million was less than the decrease in income tax expense of $6.1 million.

Adjusted EBITDA

For fiscal 2012, Adjusted EBITDA decreased by $21.2 million, or 24.3%, to $66.1 million as the impact of 21.4% warmer temperatures, net customer attrition and other reductions in home heating oil and propane volume more than offset an increase in Adjusted EBITDA provided by fiscal 2012 and 2011 acquisitions, an increase in home heating oil and propane per gallon gross profit margins, $12.5 million recorded under the Partnership’s weather hedge contract and lower operating expenses.

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 pay distributions.

EBITDA and Adjusted EBITDA are calculated as follows:

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##### Table of Contents

|  | Fiscal Year Ended September 30, |
(in thousands) |  | 2012 |  |  | 2011 |
Income (loss) from continuing operations |  | $ | 25,989 |  |  | $ | 24,344 |
Plus: |  |  |  |  |  |  |  |
Income tax expense |  |  | 16,576 |  |  |  | 22,723 |
Amortization of debt issuance cost |  |  | 1,634 |  |  |  | 2,440 |
Interest expense, net |  |  | 14,060 |  |  |  | 15,654 |
Depreciation and amortization |  |  | 16,395 |  |  |  | 17,884 |
EBITDA (a) (b) from continuing operations |  |  | 74,654 |  |  |  | 83,045 |
(Increase) / decrease in the fair value of derivative instruments |  |  | (8,549 | ) |  |  | 2,567 |
Gain on redemption of debt |  |  | — |  |  |  | 1,700 |
Adjusted EBITDA (a) (b) |  |  | 66,105 |  |  |  | 87,312 |
Add / (subtract) |  |  |  |  |  |  |  |
Income tax expense |  |  | (16,576 | ) |  |  | (22,723 | )
Interest expense, net |  |  | (14,060 | ) |  |  | (15,654 | )
Provision for losses on accounts receivable |  |  | 6,017 |  |  |  | 10,388 |
(Increase) decrease in accounts receivables |  |  | 5,804 |  |  |  | (31,593 | )
(Increase) decrease in inventories |  |  | 34,335 |  |  |  | (13,189 | )
Increase (decrease) in customer credit balances |  |  | 11,952 |  |  |  | (1,776 | )
Change in deferred taxes |  |  | 12,913 |  |  |  | 15,831 |
Change in other operating assets and liabilities |  |  | (662 | ) |  |  | 10,806 |
Net cash provided by operating activities |  | $ | 105,828 |  |  | $ | 39,402 |
Net cash used in investing activities |  | $ | (44,517 | ) |  | $ | (15,928 | )
Net cash provided by (used in) financing activities |  | $ | (40,009 | ) |  | $ | 2,253 |

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

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

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

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

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

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

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

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

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

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

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

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

(b) | As a result of the reclassification of finance charge income, as described in Note 2 of the Consolidated Financial Statements—Summary of Significant Accounting Policies Reclassification, operating income, EBITDA and Adjusted EBITDA have been revised but net income has not changed.

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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 may 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 fiscal 2013, cash provided by operating activities decreased by $87.3 million to $18.5 million, when compared to $105.8 million of cash provided by operating activities during fiscal 2012, as a favorable change in cash generated from operations of $9.5 million and increases in accruals for insurance, interest and profit sharing totaling $5.9 million were reduced by an increase in inventory of $55.0 million, an increase in cash needs to fund accounts receivable of $19.9 million and the timing of cash receipts from budget customers of $27.8 million. The impact of 22.3% colder temperatures in fiscal 2013 compared to fiscal 2012 was the primary driver of the change in cash required to finance accounts receivable as well as the change in customer credit balances. Days sales outstanding as of September 30, 2013 were 53 days compared to 50 days at September 30, 2012 and 61 days at September 30, 2011. At the beginning of fiscal 2012, the Partnership had increased its quantity of liquid product on hand to take advantage of certain market conditions. These market conditions did not occur at the end of fiscal 2012 and the Partnership reduced its inventory which resulted in an increase in cash of $34.1 million. At the end of fiscal 2013 the Partnership increased the quantity of liquid inventory to almost the level at the beginning of fiscal 2012. This change resulted in a use of cash in fiscal 2013 of $19.4 million.

For fiscal 2012, cash provided by operating activities was $105.8 million or $66.4 million greater than cash provided by operating activities for fiscal 2011 of $39.4 million. While cash generated from operations declined by $20.7 million largely due to the impact of 21.4% warmer weather, cash used to finance accounts receivable declined by $37.4 million, as the impact of lower volume sold due to the warmer weather more than offset the effects of higher selling prices. As a result, days sales outstanding declined to 50 days as of September 30, 2012, compared to 61 days at September 30, 2011. Cash collected from our budget payment plan customers also favorably impacted the year to year comparison by $13.7 million, as sales for fiscal 2012 were less than expected due to the warm weather and when compared to fiscal 2011. Changes in per gallon inventory values and quantities drove a favorable change in cash needs of $47.5 million. In fiscal 2012, the Partnership reduced inventory quantities to a greater extent than fiscal 2011, which provided $34.1 million in cash and more than offset a $0.07 per gallon increase in inventory cost. In fiscal 2011, the ending inventory cost increased by $1.36 per gallon which led to a $13.2 million use of cash. However, the timing of payments for insurance, interest and amounts due under the Partnership’s profit sharing plan resulted in a $11.5 million greater use of cash for fiscal 2012 compared to fiscal 2011.

Investing Activities

Our capital expenditures for fiscal 2013 totaled $6.0 million, as we invested in computer hardware and software ($1.9 million), refurbished certain physical plants ($1.2 million), expanded our propane operations ($1.9 million) and made additions to our fleet and other equipment ($1.0 million). We also completed two acquisitions for $1.4 million and allocated $1.3 million of the gross purchase price to intangible assets, $0.2 million to fixed assets and reduced working capital by $0.1 million of credits.

Capital expenditures for fiscal 2012 totaled $5.8 million, as we invested in computer hardware and software ($1.8 million), refurbished certain physical plants ($0.8 million), expanded our propane operations ($1.4 million) and made additions to our fleet and other equipment ($1.8 million). We also completed five acquisitions for $39.2 million and allocated $32.4 million of the gross purchase price to intangible assets, $8.0 million to fixed assets less $1.2 million in working capital.

Financing Activities

During fiscal 2013, we borrowed $111.5 million under our credit facility and repaid $111.5 million during the period. We also paid distributions of $19.0 million to our common unit holders, $0.3 million to our general partner (including $0.17 million of incentive distributions as provided in our Partnership Agreement) and repurchased 3.3 million units for $15.2 million in connection with our unit repurchase plan.

During fiscal 2012, we borrowed $86.3 million under our credit facility and repaid $86.3 million during the period. We also paid distributions of $19.3 million to our common unit holders, $0.2 million to our general partner (including $0.1 million of incentive distributions as provided in our Partnership Agreement) and repurchased 4.0 million units for $19.6 million in connection with our unit repurchase plan.

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FINANCING AND SOURCES OF LIQUIDITY

Liquidity and Capital Resources

Our primary uses of liquidity are to provide funds for our working capital, capital expenditures, distributions on our units, acquisitions and unit repurchases. Our ability to provide funds for such uses depends on our future performance, which will be subject to prevailing economic, financial, business and weather conditions, the ability to pass on the full impact of high product costs to customers, the effects of high net customer attrition, conservation and other factors. Capital requirements, at least in the near term, are expected to be provided by cash flows from operating activities, cash on hand as of September 30, 2013 ($85.1 million) or a combination thereof. To the extent future capital requirements exceed cash on hand plus cash flows from operating activities, we anticipate that working capital will be financed by our revolving credit facility, as discussed below, and repaid from subsequent seasonal reductions in inventory and accounts receivable. If we require additional capital and the credit markets are receptive, we may seek to offer and sell debt or equity securities under our $250 million shelf registration statement.

Our asset based revolving credit facility, which expires in June 2016, provides us with the ability to borrow up to $250 million ($350 million during the heating season from November through April of each year) for working capital purposes (subject to certain borrowing base limitations and coverage ratios), including the issuance of up to $100 million in letters of credit. We can increase the facility size by $100 million without the consent of the bank group. However, the bank group is not obligated to fund the $100 million increase. If the bank group elects not to fund the increase, we can add additional lenders to the group, with the consent of the Agent, which shall not be unreasonably withheld. Obligations under the revolving credit facility are guaranteed by us and our subsidiaries and secured by liens on substantially all of our assets, including accounts receivable, inventory, general intangibles, real property, fixtures and equipment. As of September 30, 2013, there were no borrowings under our revolving credit facility and $44.7 million in letters of credit were outstanding for current and future insurance reserves and bonds.

Under the terms of the revolving credit facility, we must maintain at all times either Availability (borrowing base less amounts borrowed and letters of credit issued) of 12.5% of the maximum facility size or a fixed charge coverage ratio of not less than 1.1, which is calculated based upon Adjusted EBITDA for the trailing twelve month period. As of September 30, 2013, Availability, as defined in the revolving credit facility agreement, was $164.3 million and we were in compliance with the fixed charge coverage ratio.

Maintenance capital expenditures for fiscal 2014 are estimated to be approximately $5.0 to $6.0 million, excluding the capital requirements for leased fleet. In addition, we plan to invest an estimated $1.5 million in our propane operations. Paying distributions during fiscal 2014 at the current quarterly level of $0.0825 per unit, would result in an aggregate of approximately $19.0 million to common unit holders, $0.28 million to our general partner (including $0.19 million of incentive distribution as provided in our Partnership Agreement) and $0.19 million to management pursuant to the management incentive compensation plan which provides for certain members of management to receive incentive distributions that would otherwise be payable to the general partner. For fiscal 2014, the Partnership’s scheduled interest payments on its Senior Notes, which are due in November 2017, amount to $11.1 million. Based upon the funding requirements of the Pension Protection Act, and certain actuarial assumptions, we estimate that the Partnership will be required to make cash contributions to its frozen defined benefit pension obligations totaling approximately $6.1 million over the next five fiscal years. In addition, we will 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.

Partnership Distribution Provisions

On October 29, 2013, we declared a quarterly distribution of $0.0825 per unit, or $0.33 per unit on an annualized basis, on all common units with respect to the fourth quarter of fiscal 2013 payable on November 14, 2013 to holders of record on November 8, 2013. In accordance with our Partnership Agreement, the amount of distributions in excess of the minimum quarterly distribution of $0.0675, are distributed 90% to the holders of common units and 10% to the holders of the general partner units (until certain distribution levels are met), subject to the management incentive compensation plan. As a result, $4.7 million was paid to the common unit holders, $0.07 million to the general partner (including $0.05 million of incentive distribution as provided in our Partnership Agreement) and $0.05 million to management pursuant to the management incentive compensation plan, which provides for certain members of management to receive incentive distributions that would otherwise be payable to the general partner.

(See Part II—Item 5. Market for Registrant’s Units and Related Matters—Partnership Distribution Provisions and Note 4 Quarterly Distribution of Available Cash)

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Contractual Obligations and Off-Balance Sheet Arrangements

We have no special purpose entities or off balance sheet debt, other than operating leases entered into in the ordinary course of business.

Long-term contractual obligations, except for our long-term debt obligations, are not recorded in our consolidated balance sheet. Non-cancelable purchase obligations are obligations we incur during the normal course of business, based on projected needs. The Partnership had no capital lease obligations as of September 30, 2013.

Reserves for income taxes under FASB ASC 740-10-05 Income Taxes (“FIN 48”) are not included in the table because we cannot reasonably predict the ultimate timing of settlement of our reserves for income taxes with the respective taxing authorities.

The table below summarizes the payment schedule of our contractual obligations at September 30, 2013 (in thousands):

|  | Payments Due by Fiscal Year |
|  | Total |  |  | 2014 |  |  | 2015 and 2016 |  |  | 2017 and 2018 |  |  | Thereafter |
Long-term debt obligations |  | $ | 125,000 |  |  | $ | — |  |  | $ | — |  |  | $ | 125,000 |  |  | $ | — |
Operating lease obligations (a) |  |  | 53,433 |  |  |  | 13,819 |  |  |  | 22,022 |  |  |  | 10,673 |  |  |  | 6,919 |
Purchase obligations and other (b) |  |  | 28,060 |  |  |  | 10,717 |  |  |  | 9,980 |  |  |  | 6,560 |  |  |  | 803 |
Interest obligations (c) |  |  | 47,525 |  |  |  | 12,394 |  |  |  | 22,188 |  |  |  | 12,943 |  |  |  | — |
Long-term liabilities reflected on the balance sheet (d) |  |  | 3,296 |  |  |  | 350 |  |  |  | 700 |  |  |  | 700 |  |  |  | 1,546 |
|  | $ | 257,314 |  |  | $ | 37,280 |  |  | $ | 54,890 |  |  | $ | 155,876 |  |  | $ | 9,268 |

(a) | Represents various operating leases for office space, trucks, vans and other equipment with third parties.

(b) | Represents non-cancelable commitments as of September 30, 2013 for operations such as weather hedge premiums, customer related invoice and statement processing, voice and data phone/computer services and real estate taxes on leased property.

(c) | Reflects 8.875% interest obligations on our $125.0 million senior notes (excluding discounts) due December 2017 and the unused commitment fee on the revolving credit facility.

(d) | Reflects long-term liabilities excluding a pension accrual of approximately $4.3 million. We estimate minimum cash contributions of approximately $2.7 million for fiscal 2014 and an average of approximately $0.9 million for each of the fiscal years 2015 through 2018.

Recent Accounting Pronouncements

In fiscal 2013, the provisions of FASB ASU No. 2011-08, Intangibles-Goodwill and Other (350): Testing Goodwill for Impairment became effective. This standard simplifies how entities test goodwill for impairment by providing for an optional qualitative assessment in determining whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount, as a basis for determining whether it is necessary to perform the first step, of the two-step goodwill impairment test. We did not elect to perform the optional qualitative test in fiscal 2013.

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

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Critical Accounting Estimates

The preparation of financial statements in conformity with Generally Accepted Accounting Principles requires management to establish accounting policies and make estimates and assumptions that affect reported amounts of assets and liabilities at the date of the Consolidated Financial Statements. The Partnership evaluates its policies and estimates on an on-going basis. A change in any of these critical accounting estimates could have a material effect on the results of operations. The Partnership’s Consolidated Financial Statements may differ based upon different estimates and assumptions. The Partnership’s critical accounting estimates have been reviewed with the Audit Committee of the Board of Directors.

Our significant accounting policies are discussed in Note 2 of the Notes to the Consolidated Financial Statements. We believe the following are our critical accounting policies and estimates:

Goodwill and Other Intangible Assets

We calculate amortization using the straight-line method over periods ranging from five to twenty years for intangible assets with finite useful lives based on historical statistics. We use amortization methods and determine asset values based on our best estimates using reasonable and supportable assumptions and projections. For significant acquisitions we may engage a third party valuation firm to assist in the valuation of intangible assets of that acquisition. We assess the useful lives of intangible assets based on the estimated period over which we will receive benefit from such intangible assets such as historical evidence regarding customer churn rate. In some cases, the estimated useful lives are based on contractual terms. At September 30, 2013, we had $66.8 million of net intangible assets subject to amortization. If lives were shortened by one year, we estimate that amortization for these assets for fiscal 2013 would have increased by approximately $1.4 million.

FASB ASC 350-10-05, Intangibles-Goodwill and Other, requires goodwill to be assessed at least annually for impairment. These assessments involve management’s estimates of future cash flows, market trends and other factors to determine the fair value of the reporting unit, which includes the goodwill to be assessed. If the carrying amount of a reporting unit exceeds its fair value, an impairment charge is recorded if the carrying value of goodwill is determined to be greater than its fair value. At September 30, 2013, we had $201.1 million of goodwill.

The Partnership has one reporting segment. We test the carrying amount of goodwill annually during the fourth fiscal quarter. It was determined based on this analysis that there was no goodwill impairment as of August 31, 2013. The preparation of this analysis was based upon management’s estimates and assumptions, and future impairment calculations would be affected by actual results that are materially different from projected amounts. To provide for a sensitivity of the discount rates and transaction multiples used, ranges of high and low values are employed in the analysis, with the low values examined to ensure that a reasonably likely change in an assumption would not cause the Partnership to reach a different conclusion.

Although the Partnership believes that its projections reflect its best estimates of future performance, changes in estimated revenues, per gallon margins or discount rates may have an impact on the estimated fair value. Any increase in estimated cash flows or a decrease in the discount rate would not have an impact on the carrying value of the goodwill. A decrease in future estimated cash flows or an increase in the discount rate could require the Partnership to determine whether the recognition of a goodwill impairment charge would be required.

The Partnership estimates the fair value of its sole reporting unit utilizing two generally accepted approaches: the Income Approach and the Market Approach (which is a combination of the Market Comparable and the Market Transaction Approaches).

The Income Approach uses management’s projections of cash flows, market trends and other factors to determine the value of the reporting unit based on discounted cash flows. The Partnership’s discount rate was calculated based on the weighted average cost of capital, using inputs of comparable companies in the same industry. The Partnership’s conclusion of the fair value of the reporting unit was supported based on a sensitivity analysis performed using a range of discount rates and terminal multiples.

The Market Comparable Approach determines a fair value of the reporting unit based on comparable companies in similar industries, whose securities are actively traded in public markets. A financial multiple range was calculated and applied to the financial metrics of the Partnership. The Partnership’s conclusion was supported using the high and low range of multiples applied.

The Market Transaction Approach determines a fair value of the reporting unit based on exchange prices in actual sales and purchases of comparable businesses. A transaction multiple was calculated and applied to the financial metrics of the Partnership. In addition, a transaction occurring after the analysis date, but before the fiscal year-end was reviewed, and the Partnership’s conclusion of value was supported based on the calculations of these transaction multiples.

In addition, the Partnership performs a reasonableness check of its concluded value for its sole reporting unit by reconciling the results of the goodwill analysis with its market capitalization.

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Intangible assets with finite lives must be assessed for impairment whenever changes in circumstances indicate that the assets may be impaired. The assessment for impairment requires estimates of future cash flows related to the intangible asset. To the extent the carrying value of the assets exceeds its future undiscounted cash flows, an impairment loss is recorded based on the fair value of the asset.

Depreciation of Property and Equipment

Depreciation is calculated using the straight-line method based on the estimated useful lives of the assets ranging from 1 to 30 years. Net property and equipment was $51.3 million at September 30, 2013. If the remaining estimated useful lives of these assets were shortened by one year, we estimate that depreciation for fiscal 2013 would have increased by approximately $1.5 million.

Fair Values of 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. The Partnership has elected not to designate its derivative instruments as hedging instruments under this guidance, and the change in fair value of the derivative instruments are recognized in our statement of operations.

We have established the fair value of our derivative instruments using estimates determined by our counterparties and subsequently evaluated them internally using established index prices and other sources. These values are based upon, among other things, future prices, volatility, time-to-maturity value and credit risk. The estimate of fair value we report in our financial statements changes as these estimates are revised to reflect actual results, changes in market conditions, or other factors, many of which are beyond our control.

Defined Benefit Obligations

FASB ASC 715-10-05, Compensation-Retirement Benefits, requires an employer to (i) measure the funded status of a defined benefit postretirement plan as of the date of its fiscal year-end statement of financial position, (ii) to recognize the overfunded or underfunded status of this plan as an asset or liability in its statement of financial position and (iii) to recognize changes in that funded status in the year which the changes occur through comprehensive income.

This standard requires the Partnership to make assumptions as to the expected long-term rate of return that could be achieved on defined benefit plan assets and discount rates to determine the present value of the plans’ pension obligations. The Partnership evaluates these critical assumptions at least annually.

The discount rate enables the Partnership to state expected future cash flows at a present value on the measurement date. The rate is required to represent the market rate for high-quality fixed income investments. A lower discount rate increases the present value of benefit obligations and increases pension expense in the following fiscal year. A 25 basis point decrease in the discount rate used for fiscal 2013 would have increased pension expense by approximately $0.1 million and would have increased the pension liability by another $2.0 million. The discount rate used to determine net periodic pension expense was 3.50% in 2013, 4.35% in 2012, and 4.7% in 2011. The discount rate used in determining end of year pension obligations was 4.45% in 2013, 3.5% in 2012, and 4.35% in 2011. These rates reflect the yield of high quality (AA or better rating by a recognized rating agency) corporate bonds whose cash flows are expected to match the timing and amounts of future benefit payments.

We consider the current and expected asset allocations, as well as historical and expected returns on various categories of plan assets to determine our expected long-term rate of return on pension plan assets. The expected long-term rate of return on assets is developed with input from the Partnership’s investment advisors. The long-term rate of return assumption used for determining net periodic pension expense for fiscal 2013 was 7.00% and 7.75% for fiscal 2012. A further 25 basis point decrease in the expected return on assets would have increased pension expense in fiscal 2013 by approximately $0.1 million. As the Plan gets closer to being fully funded, the asset allocations have been adjusted to lower volatility from equity holdings (currently 80% domestic fixed income, 15% domestic equities and 5% international equities). For fiscal year 2014, the Partnership revised its return on plan assets assumption to 5.75% per annum.

Over the life of the plans, both gains and losses have been recognized by the plans in the calculation of annual pension expense. As of September 30, 2013, $25.5 million of unrecognized losses remain to be recognized by the plans. These losses may result in increases in future pension expense as they are recognized.

In addition, we participate in a number of trustee-managed multi-employer pension and health and welfare plans for employees covered under collective bargaining agreements. The Partnership makes timely contributions as required by the plans. Several factors could result in potentially higher future contributions to these plans, including unfavorable investment performance, insolvency of participating employers, changes in demographics, and increased benefits to participants.

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Allowance for Doubtful Accounts

The allowance for doubtful accounts is the Partnership’s best estimate of the amount of trade receivables that may not be collectible. The allowance is determined at an aggregate level (as opposed to account by account) by grouping accounts based on the type of account and its receivable aging. The allowance is based on both quantitative and qualitative factors, including historical loss experience, historical collection patterns, overdue status, aging trends, and current economic conditions. The Partnership has an established process to periodically review current and past due trade receivable balances to determine the adequacy of the allowance. No single statistic or measurement determines the adequacy of the allowance. The total allowance reflects management’s estimate of losses inherent in its trade receivables at the balance sheet date. Different assumptions or changes in economic conditions could result in material changes to the allowance for doubtful accounts.

Insurance Reserves

We currently self-insure a portion of workers’ compensation, auto and general liability claims. We establish reserves based upon expectations as to what our ultimate liability may be for outstanding claims using developmental factors based upon historical claim experience, supplemented by a third-party actuary. We periodically evaluate the potential for changes in loss estimates with the support of qualified actuaries. As of September 30, 2013, we had approximately $51.3 million of insurance reserves. The ultimate resolution of these claims could differ materially from the assumptions used to calculate the reserves, which could have a material adverse effect on results of operations.

ITEM 7A. | 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 September 30, 2013, we had outstanding borrowings totaling $125.0 million (excluding discounts), none of which is subject to variable interest rates.

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. 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 September 30, 2013, the potential impact on our hedging activity would be to increase the fair market value of these outstanding derivatives by $14.1 million to a fair market value of $10.7 million; and conversely a hypothetical ten percent decrease in the cost of product would decrease the fair market value of these outstanding derivatives by $6.0 million to a negative fair market value of $(9.4) million.

ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The financial statements and financial statement schedules referred to in the index contained on page F-1 of this report are incorporated herein by reference.

ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

NONE

ITEM 9A. | CONTROLS AND PROCEDURES

(a) Evaluation of disclosure controls and procedures.

The general partner’s principal executive officer and its principal financial officer evaluated the effectiveness of the Partnership’s disclosure controls and procedures (as that term is defined in Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended) as of September 30, 2013. Based on that evaluation, such principal executive officer and principal financial officer concluded that the Partnership’s disclosure controls and procedures were effective as of September 30, 2013 at the reasonable level of assurance. For purposes of Rule 13a-15(e), the term disclosure controls and procedures means controls and other procedures of an issuer that are designed to ensure that information required to be disclosed by the issuer in the reports that it files or submits under the Act (15 U.S.C. 78a et seq.) is recorded, processed, summarized and reported, within the time periods specified in the Commission’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Act is accumulated and communicated to the issuer’s management, including its principal executive and principal financial officer, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

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(b) Management’s Report on Internal Control over Financial Reporting.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) under the Securities Exchange Act of 1934, as amended. Under the supervision of management and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, September 1992. Based on our evaluation of internal Control over financial reporting, our management concluded that our internal control over financial reporting was effective as of September 30, 2013. The effectiveness of our internal control over financial reporting as of September 30, 2013 has been audited by our independent registered public accounting firm, as stated in their report which is included herein.

(c) Change in Internal Control over Financial Reporting.

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

(d) Other.

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

ITEM 9B. | OTHER INFORMATION

Not applicable.

PART III

ITEM 10. | DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Partnership Management

Our general partner is Kestrel Heat. The Board of Directors of Kestrel Heat is appointed by its sole member, Kestrel, which is a private equity investment partnership formed by Yorktown Energy Partners VI, L.P., Paul A. Vermylen Jr. and other investors.

Kestrel Heat, as our general partner, oversees our activities. Unitholders do not directly or indirectly participate in our management or operation or elect the directors of the general partner. The Board of Directors (sometimes referred to as the “Board”) of Kestrel Heat has adopted a set of Partnership Governance Guidelines in accordance with the requirements of the New York Stock Exchange. A copy of these Guidelines is available on our website at www.Star-Gas.com or a copy may be obtained without charge by contacting Richard F. Ambury, (203) 328-7310.

As of November 30, 2013, Kestrel Heat and its affiliates owned an aggregate of 13,261,350 common units, representing 23.08% of the issued and outstanding common units, and Kestrel Heat owned 325,729 general partner units.

The general partner owes a fiduciary duty to the unitholders. However, our Partnership Agreement contains provisions that allow the general partner to take into account the interests of parties other than the limited partners in resolving conflict of interest, thereby limiting such fiduciary duty. Notwithstanding any limitation on obligations or duties, the general partner will be liable, as our general partner, for all our debts (to the extent not paid by us), except to the extent that indebtedness or other obligations incurred by us are made specifically non-recourse to the general partner.

As is commonly the case with publicly traded limited partnerships, the general partner does not directly employ any of the persons responsible for managing or operating the Partnership.

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Directors and Executive Officers of the General Partner

Directors are appointed for an indefinite term, subject to the discretion of Kestrel. The following table shows certain information for directors and executive officers of the general partner as of November 30, 2013:

Name |  | Age |  |  | Position
Paul A. Vermylen, Jr. |  |  | 66 |  |  | Chairman, Director
Steven J. Goldman |  |  | 53 |  |  | President, Chief Executive Officer and Director
Richard F. Ambury |  |  | 56 |  |  | Chief Financial Officer, Executive Vice President, Treasurer and Secretary
Richard G. Oakley |  |  | 53 |  |  | Vice President and Controller
Henry D. Babcock(1) |  |  | 73 |  |  | Director
C. Scott Baxter(1) |  |  | 52 |  |  | Director
Daniel P. Donovan |  |  | 67 |  |  | Director
Bryan H. Lawrence |  |  | 71 |  |  | Director
Sheldon B. Lubar |  |  | 84 |  |  | Director
William P. Nicoletti (1) |  |  | 68 |  |  | Director

(1) | Audit Committee member

Paul A. Vermylen, Jr. Mr. Vermylen has been the Chairman and a director of Kestrel Heat since April 28, 2006. Mr. Vermylen is a founder of Kestrel and has served as its President and as a manager since July 2005. Mr. Vermylen had been employed since 1971, serving in various capacities, including as a Vice President of Citibank N.A. and Vice President-Finance of Commonwealth Oil Refining Co. Inc. Mr. Vermylen served as Chief Financial Officer of Meenan Oil Co., L.P. (“Meenan”) from 1982 until 1992 and as President of Meenan until 2001, when we acquired Meenan. Since 2001, Mr. Vermylen has pursued private investment opportunities. Mr. Vermylen serves as a director of certain non-public companies in the energy industry in which Kestrel holds equity interests including Downeast LNG, Inc. and Moneta Energy Services Ltd. Mr. Vermylen is a graduate of Georgetown University and has an M.B.A. from Columbia University.

Mr. Vermylen’s substantial experience in the home heating oil industry and his leadership skills and experience as an executive officer of Meenan, among other factors, led the Board to conclude that he should serve as the Chairman and a director of Kestrel Heat.

Steven J. Goldman. Mr. Goldman has been President and Chief Executive Officer of Kestrel Heat since October 1, 2013. Mr. Goldman has been a director of Kestrel Heat since October 29, 2013. From May 1, 2010 to September 30, 2013, Mr. Goldman was Executive Vice President and Chief Operating Officer of Kestrel Heat, and was Senior Vice President of Operations from April 1, 2007 until April 30, 2010. Mr. Goldman was Vice President of Operations of Petro Holdings, Inc. from July 2004 until May 31, 2007. From February 2000 to June 2004, Mr. Goldman held various operating management positions with Petro. Prior to joining Petro Holdings, Inc. as a General Manager in 2000, Mr. Goldman worked for United Parcel Service from 1982 to 2000. Mr. Goldman has also held various positions within the management of companies in industrial engineering and those with international operations. Mr. Goldman is a graduate of the State University of New York at Stony Brook.

Mr. Goldman’s in-depth knowledge of the Partnership’s business and his substantial experience in the home heating oil industry, among other factors, led the Board to conclude that he should serve as a director of Kestrel Heat.

Richard F. Ambury. Mr. Ambury has been Executive Vice President of Kestrel Heat since May 1, 2010 and has been Chief Financial Officer, Treasurer and Secretary of Kestrel Heat since April 28, 2006. Mr. Ambury was Chief Financial Officer, Treasurer and Secretary of Star Gas from May 2005 until April 28, 2006. From November 2001 to May 2005, Mr. Ambury was Vice President and Treasurer of Star Gas. From March 1999 to November 2001, Mr. Ambury was Vice President of Star Gas Propane, L.P. From February 1996 to March 1999, Mr. Ambury served as Vice President—Finance of Star Gas Corporation, a predecessor general partner. Mr. Ambury was employed by Petroleum Heat and Power Co., Inc. from June 1983 through February 1996, where he served in various accounting/finance capacities. From 1979 to 1983, Mr. Ambury was employed by a predecessor firm of KPMG, a public accounting firm. Mr. Ambury has been a Certified Public Accountant since 1981 and is a graduate of Marist College.

Richard G. Oakley. Mr. Oakley has been Vice President and Controller of Kestrel Heat since May 22, 2006. From September 1982 until May 2006 he held various positions with Meenan Oil Co. LP, most recently that of Controller since 1993. Mr. Oakley is a graduate of Long Island University.

Henry D. Babcock. Mr. Babcock has been a director of Kestrel Heat since April 28, 2006. Mr. Babcock is a consultant to Train, Babcock Advisors LLC, a privately owned registered investment advisor. He joined the firm in 1976, became a partner in 1980, CEO in 1999 and Chairman in 2006. Prior to this, he ran an affiliated venture capital company that was active the in the U.S. and abroad. Mr. Babcock is a graduate of Yale University and received an MBA from Columbia University. He is President of The Caumsett Foundation, Inc.

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Mr. Babcock’s significant experience in capital markets, corporate finance and venture capital, among other factors, led the Board to conclude that he should serve as a director of Kestrel Heat.

C. Scott Baxter. Mr. Baxter has been a director of Kestrel Heat since April 28, 2006. Mr. Baxter is currently a senior member of Petrie Partners, an energy investment banking firm, and manages their Houston office. Prior to joining Petrie Partners in 2013, Mr. Baxter was Managing Partner of Baxter Energy Partners, a corporate energy M&A advisory firm which he founded. He previously held positions including Head of the Americas for J.P. Morgan’s global energy group, Managing Director in the global energy group at Citigroup (Salomon Brothers) and head of the energy group for Houlihan Lokey. Mr. Baxter has 25 years of energy investment banking experience and has been a primary advisor in executing over $150 billion in corporate energy M&A, restructuring and private equity financing transactions. Mr. Baxter has also rendered over 30 independent fairness opinions for boards spanning the upstream to MLP sectors in the energy industry. Mr. Baxter holds a B.S. degree in Economics from Weber State University where he graduated cum laude, and received an MBA degree from the University of Chicago Graduate School of Business. Mr. Baxter has served as an adjunct professor of finance at Columbia University’s Graduate School of Business and been on the President’s advisory board for Weber State University since 1996.

Mr. Baxter’s significant experience as an investor and senior investment banker focused on the energy field, among other factors, led the Board to conclude that he should serve as a director of Kestrel Heat.

Daniel P. Donovan. Mr. Donovan has been a director of Kestrel Heat since April 28, 2006. Mr. Donovan was Chief Executive Officer of Kestrel Heat from May 31, 2007 to September 30, 2013 and had been President from April 28, 2006 to September 30, 2013. From April 28, 2006 to May 30, 2007 Mr. Donovan was also the Chief Operating Officer of Kestrel Heat. Mr. Donovan was the President and Chief Operating Officer of a predecessor general partner, Star Gas LLC (“Star Gas”), from March 2005 until April 28, 2006. From May 2004 to March 2005 he was President and Chief Operating Officer of the Star Gas heating oil segment. Mr. Donovan held various management positions with Meenan Oil Co. LP, from January 1980 to May 2004, including Vice President and General Manager from 1998 to 2004. Mr. Donovan worked for Mobil Oil Corp. from 1971 to 1980. His last position with Mobil was President and General Manager of its heating oil subsidiary in New York City and Long Island. Mr. Donovan is a graduate of St. Francis College in Brooklyn, New York and received an M.B.A. from Iona College.

Mr. Donovan’s in-depth knowledge of the Partnership’s business, having been its president and chief executive officer, and his substantial experience in the home heating oil industry, among other factors, led the Board to conclude that he should serve as a director of Kestrel Heat.

Bryan H. Lawrence. Mr. Lawrence has been a director of Kestrel Heat since April 28, 2006 and a manager of Kestrel since July 2005. Mr. Lawrence is a founder and senior manager of Yorktown, the manager of the Yorktown group of investment partnerships, which make investments in companies engaged in the energy industry. The Yorktown partnerships were formerly affiliated with the investment firm of Dillon, Read & Co. Inc., where Mr. Lawrence was employed beginning in 1966, serving as a Managing Director until the merger of Dillon Read with SBC Warburg in September 1997. Mr. Lawrence also serves as a director of Approach Resources, Inc., Crosstex Energy, Inc., Hallador Petroleum Company (each a United States publicly traded company), Winstar Resources Ltd. (a Canadian public company) and certain non-public companies in the energy industry in which Yorktown partnerships hold equity interests. Mr. Lawrence also serves as a director of Crosstex Energy GP, LLC, the general partner of Crosstex Energy, L.P. (a United States publicly traded company). Mr. Lawrence is a graduate of Hamilton College and received an M.B.A. from Columbia University.

Mr. Lawrence’s significant financial and investment experience, and experience as a founder of Yorktown Energy Partners LLC, among other factors, led the Board to conclude that he should serve as a director of Kestrel Heat.

Sheldon B. Lubar. Mr. Lubar has been a director of Kestrel Heat since April 28, 2006 and a manager of Kestrel since July 2005. Mr. Lubar has been Chairman of the board of Lubar & Co. Incorporated, a private investment and venture capital firm he founded, since 1977. He was Chairman of the board of Christiana Companies, Inc., a logistics and manufacturing company, from 1987 until its merger with Weatherford International in 1995. Mr. Lubar had also been Chairman of Total Logistics, Inc., a logistics and manufacturing company until its acquisition in 2005 by SuperValu Inc. He has served as a director of Crosstex Energy, Inc. from January 2004 until October 2012; Approach Resources, Inc. since June 2007, Crosstex Energy GP, LLC, the general partner of Crosstex Energy, L.P. from January 2004 until October 2012 and Hallador Energy Company since 2008. He is also a director of several private companies. Mr. Lubar holds a bachelor’s degree in Business Administration and a Law degree from the University of Wisconsin-Madison. He was awarded an honorary Doctor of Commercial Science degree from the University of Wisconsin-Milwaukee.

Mr. Lubar’s significant experience as a senior executive officer and as a director of other public company’s, among other factors, led the Board to conclude that he should serve as a director of Kestrel Heat.

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William P. Nicoletti. Mr. Nicoletti has been a director of Kestrel Heat since April 28, 2006. Mr. Nicoletti was the non-executive chairman of the board of Star Gas from March 2005 until April 28, 2006. Mr. Nicoletti was a director of Star Gas from March 1999 until April 28, 2006 and was a director of Star Gas Corporation from November 1995 until March 1999. Since February 1, 2009, he has been a Managing Director of Parkman Whaling LLC, a Houston, Texas based energy investment banking firm. Previously, he was Managing Director of Nicoletti & Company, Inc., a private investment banking firm. Mr. Nicoletti was formerly a senior officer and head of Energy Investment Banking for E. F. Hutton & Company, Inc., PaineWebber Incorporated and McDonald Investments, Inc. Mr. Nicoletti is a director of MarkWest Energy Partners, L.P. Mr. Nicoletti is a graduate of Seton Hall University and received an M.B.A. from Columbia University.

Mr. Nicoletti’s current and prior leadership experience in the energy investment banking industry and his significant experience in finance, accounting and corporate governance matters, among other factors, led the Board to conclude that he should serve as a director of Kestrel Heat.

Director Independence

Section 303A of the New York Stock Exchange listed company manual provides that limited partnerships are not required to have a majority of independent directors. It is the policy of the Board of Directors that the Board shall at all times have at least three independent directors or such higher number as may be necessary to comply with the applicable federal securities law requirements. For the purposes of this policy, “independent director” has the meaning set forth in Section 10A(m) of the Securities Exchange Act of 1934, as amended, any applicable stock exchange rules and the rules and regulations promulgated in the Partnership governance guidelines available on its webpage www.Star-Gas.com . The Board of Directors has determined that Messrs. Nicoletti, Babcock, and Baxter are independent directors.

Meetings of Directors

During fiscal 2013, the Board of Directors of Kestrel Heat met four times. All directors attended each meeting except for one meeting in which one director did not attend.

Committees of the Board of Directors

Kestrel Heat’s Board of Directors has one standing committee, the Audit Committee. Its members are appointed by the Board of Directors for a one-year term and until their respective successors are elected. The NYSE corporate governance standards do not require limited partnerships to have a Nominating or Compensation Committee.

Audit Committee

William P. Nicoletti, Henry D. Babcock and C. Scott Baxter have been appointed to serve on the Audit Committee, which has adopted an Audit Committee Charter. Mr. Nicoletti serves as chairman of the Audit Committee. A copy of this charter is available on the Partnership’s website at www.Star-Gas.com or a copy may be obtained without charge by contacting Richard F. Ambury (203) 328-7310. The Audit Committee reviews the external financial reporting of the Partnership, selects and engages the Partnership’s independent registered public accountants and approves all non-audit engagements of the independent registered public accountants.

Members of the Audit Committee may not be employees of Kestrel Heat’s or its affiliated companies and must otherwise meet the New York Stock Exchange and SEC independence requirements for service on the Audit Committee. The Board of Directors has determined that Messrs. Nicoletti, Babcock and Baxter are independent directors in that they do not have any material relationships with the Partnership (either directly, or as a partner, shareholder or officer of an organization that has a relationship with the Partnership) and they otherwise meet the independence requirements of the NYSE and the SEC. The Partnership’s Board of Directors has also determined that at least one member of the Audit Committee, Mr. Nicoletti, meets the SEC criteria of an “audit committee financial expert.”

During fiscal 2013, the Audit Committee of Kestrel Heat, LLC met six times. All members attended each meeting.

Reimbursement of Expenses of the General Partner

The general partner does not receive any management fee or other compensation for its management of the Partnership. The general partner is reimbursed for all expenses incurred on behalf of the Partnership, including the cost of compensation, which is properly allocable to the Partnership. The Partnership Agreement provides that the general partner shall determine the expenses that are allocable to the Partnership in any reasonable manner determined by the general partner in its sole discretion. In addition, the general partner and its affiliates may provide services to the Partnership for which a reasonable fee would be charged as determined by the general partner. There were no reimbursements in fiscal year 2013.

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Adoption of Code of Business Conduct and Ethics

The Partnership has adopted a written Code of Business Conduct and Ethics that applies to the Partnership’s officers, directors and employees. A copy of the Code of Business Conduct and Ethics is available on the Partnership’s website at www.Star-Gas.com or a copy may be obtained without charge, by contacting Investor Relations, (203) 328-7310.

Section 16(a) Beneficial Ownership Reporting Compliance

Based on copies of reports furnished to us, we believe that during fiscal year 2013, all reporting persons complied with the Section 16(a) filing requirements applicable to them.

Non-Management Directors and Interested Party Communications

The non-management directors on the Board of Directors of the general partner are Messrs. Babcock, Baxter, Lawrence, Lubar, Nicoletti and Vermylen. The non-management directors have selected Mr. Vermylen, the Chairman of the Board, to serve as lead director to chair executive sessions of the non-management directors. Interested parties who wish to contact the non-management directors as a group may do so by contacting Paul A. Vermylen, Jr. c/o Star Gas Partners, L.P., 2187 Atlantic Street, Stamford, CT 06902.

ITEM 11. | EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

The Partnership’s Amended and Restated Agreement of Limited Partnership provides that the general partner of the Partnership, Kestrel Heat, shall conduct, direct and manage all activities of the Partnership. The limited liability company agreement of the general partner provides that the business of the general partner shall be managed by a Board of Directors. The responsibility of the Board is to supervise and direct the management of the Partnership in the interest and for the benefit of the Partnership’s unitholders. Among the Board’s responsibilities is to regularly evaluate the performance and to approve the compensation of the Chief Executive Officer and, with the advice of the Chief Executive Officer, regularly evaluate the performance and approve the compensation of key executives.

As a limited partnership that is listed on the New York Stock Exchange, the Partnership is not required to have a Compensation Committee. Since the Chairman of the general partner and the majority of the Board are not employees, the Board determined that it has adequate independence to act in the capacity of a Compensation Committee to establish and review the compensation of the Partnership’s executive officers and directors. The Board is comprised of Paul A. Vermylen Jr. (Chairman), Steven J. Goldman (President and Chief Executive Officer), Daniel P. Donovan, Henry D. Babcock, C. Scott Baxter, Bryan H. Lawrence, Sheldon B. Lubar, and William P. Nicoletti.

Throughout this Report, each person who served as chief executive officer (“CEO”) during fiscal 2013, each person who served as chief financial officer (“CFO”) during fiscal 2013 and the two other most highly compensated executive officers serving at September 30, 2013 (there being no other executive officers who earned more than $100,000 during fiscal 2013) are referred to as the “named executive officers” and are included in the Executive Compensation Table.

In this Compensation Discussion and Analysis, we address the compensation paid or awarded to Messrs. Donovan, Ambury, Goldman, and Oakley. We refer to these executive officers as our “named executive officers.”

Compensation decisions for the above officers were made by the Board of Directors of the Partnership.

Compensation Philosophy and Policies

The primary objectives of the Partnership’s compensation program, including compensation of the named executive officers, are to attract and retain highly qualified officers, employees and directors and to reward individual contributions to our success. The Board of Directors considers the following policies in determining the compensation of the named executive officers:

| • |  | compensation should be related to the performance of the individual executive and the performance measured against both financial and non-financial achievements;

| • |  | compensation levels should be competitive to ensure that we will be able to attract, motivate and retain highly qualified executive officers; and

| • |  | compensation should be related to improving unitholder value over time.

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Compensation Methodology

The elements of the Partnership’s compensation program for named executive officers are intended to provide a total incentive package designed to drive performance and reward contributions in support of business strategies at the Partnership and operating unit level. Subject to the terms of employment agreements that have been entered into with the named executive officers, all compensation determinations are discretionary and subject to the decision-making authority of the Board of Directors. We do not use benchmarking as a fixed criterion to determine compensation. Rather, after subjectively setting compensation based on the policies discussed above under “Compensation Philosophy and Policies” , we reviewed the compensation paid to officers holding similar positions at our peer group companies to obtain a general understanding of the reasonableness of base salaries and other compensation payable to our named executive officers. Our peer group of companies was comprised of the following companies: Amerigas Partners, L.P., Suburban Propane Partners, L.P., Ferrellgas Partners, L.P. and Global Partners, L.P. We chose these companies because they are master limited partnerships that are engaged in the retail distribution of energy products like the Partnership.

Elements of Executive Compensation

For the fiscal year ended September 30, 2013, the principal components of compensation for the named executive officers were:

| • |  | base salary;

| • |  | annual discretionary profit sharing allocation;

| • |  | management incentive compensation plan; and

| • |  | retirement and health benefits.

Under our compensation structure, the mix of base salary, discretionary profit sharing allocation and long-term compensation provided to each executive officer varies depending on their position. The base salary for each executive officer is the only fixed component of compensation. All other compensation, including annual discretionary profit sharing allocation and long-term incentive compensation, is variable in nature.

The majority of the Partnership’s compensation allocation is weighted towards base salary and annual discretionary profit sharing allocation. For the CEO, CFO and COO, approximately 50% of the annual compensation is in the form of base salary and approximately 50% is from the discretionary profit sharing allocation. For the Vice President- Controller, approximately 65% of the annual compensation is in the form of base salary and 35% is from the discretionary profit sharing allocations. In addition, during fiscal 2013, an aggregate of $118,542 was paid to the named executive officers under the terms of the Partnership’s management incentive compensation plan and represented a small portion of the executive compensation that was paid to these officers. In the future, the amounts payable to the named executive officers under the management incentive compensation plan should increase, if the Partnership is successful in increasing the overall level of distributions payable to unitholders.

We believe that together all of our compensation components provide a balanced mix of base compensation and compensation that is contingent upon each executive officer’s individual performance and our overall performance. A goal of the compensation program is to provide executive officers with a reasonable level of security through base salary and benefits, while rewarding them through incentive compensation to achieve business objectives and create unitholder value over time. As a result, officers with lower overall compensation levels will tend to have a higher percentage of base compensation. We believe that each of our compensation components is important in achieving this goal. Base salaries provide executives with a base level of monthly income and security. Annual discretionary profit sharing allocations and long-term incentive awards provide an incentive to our executives to achieve business objectives that increase our financial performance, which creates unitholder value through continuity of, and increases in, distributions and increases in the market value of the units. In addition, we want to ensure that our compensation programs are appropriately designed to encourage executive officer retention, which is accomplished through all of our compensation elements.

Base Salary

The Board of Directors establishes base salaries for the named executive officers based on a number of factors, including:

| • |  | The historical salaries for services rendered to the Partnership and responsibilities of the named executive officer.

| • |  | The salaries of equivalent executive officers at our peer group companies.

| • |  | The prevailing levels of compensation and cost of living in the location in which the named executive officer works.

In determining the initial base compensation payable to individual named executive officers when they are first hired by the Partnership, our starting point is the historical compensation levels that the Partnership has paid to officers performing similar functions over the past few years. We also consider the level of experience and accomplishments of individual candidates and general labor market conditions, including the availability of candidates to fill a particular position. When we make adjustments to the base salaries of existing named executive officers, we review the individual’s performance, the value each named executive officer brings to us and general labor market conditions.

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Elements of individual performance considered, among others, without any specific weight given to each element, include business-related accomplishments during the year, difficulty and scope of responsibilities, effective leadership, experience, expected future contributions to the Partnership and difficulty of replacement. While base salary provides a base level of compensation intended to be competitive with the external market, the base salary for each named executive officer is determined on a subjective basis after consideration of these factors and is not based on target percentiles or other formal criteria. Although we believe that base salaries for our named executive officers are generally competitive with the external market, we do not use benchmarking as a fixed criterion to determine base compensation. Rather, after subjectively setting base salaries based on the above factors, we review the compensation paid to officers holding similar positions at our peer group companies to obtain a general understanding of the reasonableness of base salaries and other compensation payable to our named executive officers. The Partnership also takes into account geographic differences for similar positions in the New York Metropolitan area. While cost of living is considered in determining annual increases, the Partnership does not typically provide full cost of living adjustments as salary increases are constrained by budgetary restrictions and the ability to fund the Partnership’s current cash needs such as interest expense, maintenance capital, income taxes and distributions.

Profit Sharing Allocations

The Partnership maintains a profit sharing pool for employees, including named executive officers, which in fiscal 2013 was equal to approximately 6.0% of the Partnership’s earnings before income taxes, depreciation and amortization, excluding items affecting comparability (“adjusted EBITDA”). The annual discretionary profit sharing allocations paid to the named executive officers are payable from this pool. The size of the pool fluctuates based upon upward or downwards changes in adjusted EBITDA. The amount of cash paid to the named executive officers under the plan is based on the target percentages of overall compensation described above under the caption “Elements of Executive Compensation.” Depending upon the size of the profit sharing pool, the amount paid to the named officers could be more or less.

There are no set formulas for determining the amount payable to our named executive officers from the profit sharing plan. Factors considered by our CEO and the Board in determining the level of profit sharing allocations generally include, without assigning a particular weight to any factor:

| (i) | whether or not we achieved certain budgeted goals for the year and any material shortfalls or superior performances relative to expectations. Under the plan, no profit sharing was payable with respect to fiscal 2013 unless the Partnership achieved actual adjusted EBITDA for fiscal 2013 of at least 70% of the amount of budgeted adjusted EBITDA for fiscal 2013. The budget is developed annually using a bottom up process;

| (ii) | the level of difficulty associated with achieving such objectives based on the opportunities and challenges encountered during the year and;

| (iii) | significant transactions or accomplishments for the period not included in the goals for the year.

Our CEO takes these factors into consideration as well as the relative contributions of each of the named executive officers to the year’s performance in developing his recommendations for profit sharing amounts. Based on such assessment, our CEO submits recommendations to the Board of Directors for the annual profit sharing amounts to be paid to our named executive officers, for the Board’s review and approval. Similarly, the Chairman assesses the CEO’s contribution toward meeting the Partnership’s goals based upon the above factors, and recommends to the Board of Directors a profit sharing allocation for the CEO it believes to be commensurate with such contribution.

The Board of Directors retains the ultimate discretion to determine whether the named executive officers will receive annual profit sharing allocations based upon the factors discussed above.

Management Incentive Compensation Plan

In fiscal 2007, following the Partnership’s recapitalization, the Board of Directors adopted the Management Incentive Compensation Plan (the “Plan”) for employees of the Partnership. Under the Plan, employees who participate shall be entitled to receive a pro rata share of an amount in cash equal to:

| • |  | 50% of the distributions (“Incentive Distributions”) of Available Cash in excess of the minimum quarterly distribution of $0.0675 per unit otherwise distributable to Kestrel Heat pursuant to the Partnership Agreement on account of its general partner units; and

| • |  | 50% of the cash proceeds (the “Gains Interest”) which Kestrel Heat shall receive from the sale of its general partner units (as defined in the Partnership Agreement), less expenses and applicable taxes.

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The Partnership believes that the Plan provides a long-term incentive to its participants because it encourages the Partnership’s management to increase the Partnership’s available cash for distributions in order to trigger the incentive distributions that are only payable if distributions from available cash exceeds certain target distribution levels, with higher percentages of incentive distributions triggered by higher levels of distributions. Such increases are not sustainable on a consistent basis without long-term improvements in the Partnership’s operations. In addition, under certain Plan amendments that were adopted in 2012, the participation points of existing plan participants will vest and become irrevocable over a four year (three years for the CEO) period starting with the fiscal year ended September 30, 2013, provided that the participants continue to be employed by the Partnership during the vesting period. The Partnership believes that this will help ensure that the Plan participants who include our named executive officers will have a continuing personal interest in the success of the Partnership.

The pro rata share payable to each participant under the Plan is based on the number of participation points as described under “Fiscal 2013 Compensation Decisions—Management Incentive Compensation Plan.” The amount paid in Incentive Distributions is governed by the partnership agreement and the calculation of Available Cash. Available Cash from Operating Surplus (as defined in our partnership agreement) is distributed to the holders of the Partnership’s common units and general partner units in the following manner:

First, 100% to all common units, pro rata, until there has been distributed to each common unit an amount equal to the minimum quarterly distribution of $0.0675 for that quarter;

Second, 100% to all common units, pro rata, until there has been distributed to each common unit an amount equal to any arrearages in the payment of the minimum quarterly distribution for prior quarters;

Third, 100% to all general partner units, pro rata, until there has been distributed to each general partner unit an amount equal to the minimum quarterly distribution;

Fourth, 90% to all common units, pro rata, and 10% to all general partner units, pro rata, until each common unit has received the first target distribution of $0.1125; and

Finally, 80% to all common units, pro rata, and 20% to all general partner units, pro rata.

Available Cash, as defined in our partnership agreement, generally means all cash on hand at the end of the relevant fiscal quarter less the amount of cash reserves established by the Board of Directors of our general partner in its reasonable discretion for future cash requirements. These reserves are established for the proper conduct of our business, including acquisitions, the payment of debt principal and interest and for distributions during the next four quarters and to comply with applicable law and the terms of any debt agreements or other agreements to which we are subject. The Board of Directors of our general partner reviews the level of Available Cash each quarter based upon information provided by management.

To fund the benefits under the Plan, Kestrel Heat has agreed to permanently and irrevocably forego receipt of the amount of Incentive Distributions that are payable to plan participants. For accounting purposes, amounts payable to management under this Plan will be treated as compensation and will reduce both EBITDA and net income but not adjusted EBITDA. Kestrel Heat has also agreed to contribute to the Partnership, as a contribution to capital, an amount equal to the Gains Interest payable to participants in the Plan by the Partnership. The Partnership is not required to reimburse Kestrel Heat for amounts payable pursuant to the Plan.

The Plan is administered by the Partnership’s Chief Financial Officer under the direction of the Board or by such other officer as the Board may from time to time direct. Determination of the employees that participate in the Plan is under the sole discretion of the Board of Directors. In general, no payments will be made under this plan if the Partnership is not distributing cash under the Incentive Distributions described above.

Effective as of July 19, 2012, the Board of Directors adopted certain amendments (the “Plan Amendments”) to the Plan, and as amended, the Plan has been amended and restated in its entirety. Under the Plan Amendments, the number and identity of the Plan participants and their participation interests in the Plan have been frozen at the current levels. In addition, under the Plan Amendments, the plan benefits (to the extent vested) may be transferred upon the death of a participant to his or her heirs. A participant’s vested percentage of his or her plan benefits will be 100% during the time a participant is an employee or consultant of the Partnership. Following the termination of such positions, a participant’s vested percentage shall be equal to 20% for each full or partial year of employment or consultation with the Partnership starting with the fiscal year ending September 30, 2012 (33 1/3% in the case of the Partnership’s chief executive officer).

The Partnership distributed approximately $165,059 in Incentive Distributions under the Plan during fiscal 2013, including payments to the named executive officers of approximately $118,542. With regard to the Gains Interest, Kestrel Heat has not given any indication that it will sell its general partner units within the next twelve months. Thus the Plan’s value attributable to the Gains Interest currently cannot be determined.

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Retirement and Health Benefits

The Partnership offers a health and welfare and retirement program to all eligible employees. The named executive officers are generally eligible for the same programs on the same basis as other employees of the Partnership. The Partnership maintains a tax-qualified 401(k) retirement plan that provides eligible employees with an opportunity to save for retirement on a tax advantaged basis. Under the Partnership’s 401(k) plan, subject to IRS limitations, each participant can contribute from 0% to 60% of compensation. The Partnership makes a 4% (to a maximum of 5.5% for participants who had 10 or more years of service at the time the Partnership’s defined benefit plans were frozen and who have reached the age 55) core contribution of a participant’s compensation and matches 2/3 of each amount a participant contributes up to a maximum of 2.0% of a participant’s compensation, also subject to IRS limitations.

In addition, the Partnership has two frozen defined benefit pension plans that were maintained for all its eligible employees, including certain executive officers. The present value of accumulated benefits under these frozen defined benefit pension plans for certain executive officers is provided in the table labeled, Pension Plans Pursuant to Which Named Executive Officers Have an Accumulated Benefit But Are Not Currently Accruing Benefits.

Fiscal 2013 Compensation Decisions

For fiscal 2013, the foregoing elements of compensation were applied as follows:

Base Salary

The following table sets forth each named executive officer’s base salary as of October 1, 2013 and the percentage increase in his base salary over October 1, 2012. The current base salaries for our named executive officers were determined during fiscal 2013, based upon the factors discussed under the caption “Base Salary .” Mr. Donovan retired from his position as President and Chief Executive Officer effective as of September 30, 2013 so he is not included in this table. The average percentage increase in base salary for executives in our peer group was approximately 8.7%.

Name |  | Salary |  | Percentage Over Prior Year
Steven J. Goldman (a) |  | $360,000 |  | 12.0%
Richard F. Ambury |  | $338,200 |  | 2.0%
Richard G. Oakley |  | $224,500 |  | 2.4%

(a) | Mr. Goldman was appointed CEO in October 1, 2013

Annual Discretionary Profit Sharing Allocation

Based on the annual performance reviews for the Partnership’s CEO and named executive officers, the Board approved annual profit sharing allocations as reflected in the “Summary Compensation Table” and notes thereto. For fiscal 2013 the profit sharing amounts reflected in the Summary Compensation Table are 22%, 47%, 54%, and 52% higher than fiscal 2012 for Messrs. Donovan, Ambury, Goldman and Oakley, respectively. One of the Partnership’s primary performance measures for profit sharing purposes is adjusted EBITDA. This adjusted EBITDA increased by $23.9 million, or 36.0%, to $90.4 million for fiscal 2013, and the Partnership generated cash in excess of distributions paid. For the Partnership’s peer group, the average percentage increase in adjusted EBITDA was 86.6%. This increase in the Partnership’s adjusted EBITDA was due, among other reasons, to 22.3% colder weather than the prior year, margin management and expense control. In addition, the Partnership’s net customer attrition was reduced to 3.3%, the lowest level achieved over the last five years. Net customer attrition for the preceding four years averaged 5.3%. The Partnership has also launched several initiatives to increase revenues other than through the sale of home heating oil and organically expanded its presence in the distribution of propane during fiscal 2013. At the beginning of fiscal 2013, management faced many challenges as a result of the major East Coast storm, Sandy, and effectively reallocated resources to service the demands of customers affected by this significant event.

Messrs. Donovan, Ambury, Goldman and Oakley were instrumental to the Partnership’s many achievements during fiscal 2013.

Management Incentive Compensation Plan

In 2012 under the Plan Amendments adopted by the Board, the number and identity of the Plan participants and their participation points were frozen at the current levels in order to more closely align the interests of Plan participants and unitholders and to give Plan participants a continuing personal interest in the success of the Partnership.

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##### Table of Contents

The number of participation points that were previously awarded to the named executive officers was based on the length of service and level of responsibility of the named executive and the Partnership’s desire to retain the named executive, in order to promote the long-term best interest of the Partnership. In general, the largest awards were granted to the CEO and CFO, who were the most senior participants in the Plan and each of whom had more than 25 years service with the Partnership and lesser awards were granted to the remaining participants, based upon their level of responsibility and length of service, without using a fixed formula to set such awards.

In fiscal 2013, $118,542 was paid to the named executive officers under the Plan as indicated in the following chart:

|  | Fiscal 2013 |  |  | Management Incentive |
Name |  | Points |  |  | Percentage |  |  | Payments |
Daniel Donovan |  |  | 300 |  |  |  | 27.3 | % |  | $ | 45,016 |
Richard Ambury |  |  | 235 |  |  |  | 21.4 | % |  |  | 35,263 |
Steven Goldman |  |  | 215 |  |  |  | 19.5 | % |  |  | 32,261 |
Richard Oakley |  |  | 40 |  |  |  | 3.6 | % |  |  | 6,002 |
Other Plan Participants |  |  | 310 |  |  |  | 28.2 | % |  |  | 46,517 |
Total |  |  | 1,100 |  |  |  | 100.0 | % |  | $ | 165,059 |

Retirement and Health Benefits

There were no changes to the retirement and health benefits applicable to the named executive officers in fiscal 2013.

Employment Contracts and Severance Agreements

Agreement with Daniel P. Donovan

The Partnership entered into an employment agreement on November 8, 2010 with Mr. Donovan effective as of June 1, 2010. Mr. Donovan’s employment agreement was for a term of three years unless otherwise terminated in accordance with the employment agreement. Mr. Donovan served as President and Chief Executive Officer of the Partnership and its subsidiaries. The employment agreement provided for one year’s salary as severance if Mr. Donovan’s employment was terminated without cause or by Mr. Donovan for good reason. Mr. Donovan retired as the President and Chief Executive Officer of the Partnership and its subsidiaries, effective as of September 30, 2013. Mr. Donovan will continue as a director of our general partner but will not receive fees for board or committee service . In addition, in accordance with a letter agreement effective as of October 1, 2013, Mr. Donovan will serve as a consultant to us for a two year period for which he will receive consulting fees of $250,000 per annum.

Agreement with Richard F. Ambury

The Partnership entered into an employment agreement with Mr. Ambury effective as of April 28, 2008. Mr. Ambury will serve as Chief Financial Officer and Treasurer of the Partnership and its subsidiaries. The employment agreement provides for one year’s salary as severance if Mr. Ambury’s employment is terminated without cause or by Mr. Ambury for good reason.

Agreement with Steven J. Goldman

Effective October 1, 2013, Steven J. Goldman was appointed the President and Chief Executive Officer of the Partnership. Mr. Goldman entered into a three year employment agreement with the Partnership, effective as of October 1, 2013, under which his salary will be $360,000 per annum. Under his employment agreement, if Mr. Goldman is terminated for reasons other than cause or if he terminates his employment for good reason, Mr. Goldman will be entitled to one year’s salary as severance.

Agreement with Richard G. Oakley

Effective November 2, 2009, the Partnership entered into an agreement with Mr. Richard G. Oakley pursuant to which Mr. Oakley will continue to be employed as Vice President—Controller on an at-will basis, and provides for one year’s salary as severance if his employment is terminated for reasons other than cause.

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##### Table of Contents

Change In Control Agreements

We have entered into a Change In Control Agreement with Mr. Goldman, Chief Executive Officer and Mr. Ambury, Chief Financial Officer. Under the terms of each agreement, if either of these executive officers is terminated as a result of a change in control (as defined in the agreement) he will be entitled to a payment equal to two times his base annual salary in the year of such termination plus two times the average amount paid as a bonus and/or as profit sharing during the three years preceding the year of such termination. The term change in control means the present equity owners of Kestrel and their affiliates collectively cease to beneficially own equity interests having the voting power to elect at least a majority of the members of the board of directors or other governing board of the general partner of the Partnership or any successor entity to the Partnership. If a change in control were to have occurred and their employment was terminated as of the date of this report, Mr. Goldman would have received a payment of $1,532,000 and Mr. Ambury would have received a payment of $1,520,400.

Indemnification Agreements

We have entered into an indemnification agreement with each of our directors and senior executives. These agreements provide for us to, among other things, indemnify such persons against certain liabilities that may arise by reason of their status or service as directors or officers, to advance their expenses incurred as a result of a proceeding as to which they may be indemnified and to cover such person under any directors’ and officers’ liability insurance policy we choose, in our discretion, to maintain. These indemnification agreements are intended to provide indemnification rights to the fullest extent permitted under applicable indemnification rights statutes in the State of Delaware and are in addition to any other rights such person may have under our partnership agreement and the operating agreement of our general partner, and applicable law. We believe these indemnification agreements enhance our ability to attract and retain knowledgeable and experienced executives and independent, non-management directors.

Board of Directors Report

The Board of Directors of the general partner of the Partnership does not have a separate compensation committee. Executive compensation is determined by the Board of Directors.

The Board of Directors reviewed and discussed with the Partnership’s management the Compensation Discussion and Analysis contained in this annual report on Form 10-K. Based on that review and discussion, the Board of Directors recommends that the Compensation Discussion and Analysis be included in the Partnership’s annual report on Form 10-K for the year ended September 30, 2013.

Paul A. Vermylen, Jr.

Steven J. Goldman

Henry D. Babcock

C. Scott Baxter

Daniel P. Donovan

Bryan H. Lawrence

Sheldon B. Lubar

William P. Nicoletti

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##### Table of Contents

Executive Compensation Table

The following table sets forth the annual salary compensation, bonus and all other compensation awards earned and accrued by the named executive officers in the fiscal year.

|  | Summary Compensation Table |
Name and Principal Position |  | Fiscal Year |  |  | Salary |  |  | Bonus |  |  | Unit Awards |  |  | Option Awards |  |  | Non- Equity Incentive Plan Comp.(2) |  |  | Change in Pension Value and Nonqualified Deferred Comp. Earnings (3) |  |  | All Other Comp.(4) |  |  | Total |
Steven J. Goldman (1) |  |  | 2013 |  |  | $ | 324,233 |  |  |  | — |  |  |  | — |  |  |  | — |  |  | $ | 478,000 |  |  | $ | — |  |  | $ | 68,197 |  |  | $ | 870,430 |
President and |  |  | 2012 |  |  | $ | 321,300 |  |  |  | — |  |  |  | — |  |  |  | — |  |  | $ | 310,000 |  |  | $ | — |  |  | $ | 62,664 |  |  | $ | 693,964 |
Chief Executive Officer |  |  | 2011 |  |  | $ | 317,625 |  |  |  | — |  |  |  | — |  |  |  | — |  |  | $ | 430,000 |  |  | $ | — |  |  | $ | 55,001 |  |  | $ | 802,626 |
Daniel P. Donovan (1) |  |  | 2013 |  |  | $ | 415,975 |  |  |  | — |  |  |  | — |  |  |  | — |  |  | $ | 495,000 |  |  | $ | — |  |  | $ | 210,255 |  |  | $ | 1,121,230 |
Former President and |  |  | 2012 |  |  | $ | 413,100 |  |  |  | — |  |  |  | — |  |  |  | — |  |  | $ | 405,000 |  |  | $ | 40,652 |  |  | $ | 144,412 |  |  | $ | 1,003,164 |
Former Chief Executive Officer |  |  | 2011 |  |  | $ | 412,367 |  |  |  | — |  |  |  | — |  |  |  | — |  |  | $ | 570,598 |  |  | $ | 67,949 |  |  | $ | 89,722 |  |  | $ | 1,140,636 |
Richard F. Ambury |  |  | 2013 |  |  | $ | 334,433 |  |  |  | — |  |  |  | — |  |  |  | — |  |  | $ | 483,000 |  |  | $ | — |  |  | $ | 73,543 |  |  | $ | 890,976 |
Chief Financial Officer, |  |  | 2012 |  |  | $ | 331,500 |  |  |  | — |  |  |  | — |  |  |  | — |  |  | $ | 328,000 |  |  | $ | 45,171 |  |  | $ | 64,756 |  |  | $ | 769,427 |
Executive Vice President, |  |  | 2011 |  |  | $ | 327,708 |  |  |  | — |  |  |  | — |  |  |  | — |  |  | $ | 455,000 |  |  | $ | 25,422 |  |  | $ | 64,965 |  |  | $ | 873,095 |
Treasurer and Secretary |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Richard G. Oakley |  |  | 2013 |  |  | $ | 219,341 |  |  |  | — |  |  |  | — |  |  |  | — |  |  | $ | 170,000 |  |  | $ | — |  |  | $ | 37,660 |  |  | $ | 427,001 |
Vice President - Controller |  |  | 2012 |  |  | $ | 219,200 |  |  |  | — |  |  |  | — |  |  |  | — |  |  | $ | 112,000 |  |  | $ | 65,800 |  |  | $ | 36,043 |  |  | $ | 433,043 |
|  |  | 2011 |  |  | $ | 212,800 |  |  |  | — |  |  |  | — |  |  |  | — |  |  | $ | 155,000 |  |  | $ | 34,731 |  |  | $ | 37,137 |  |  | $ | 439,668 |

(1) | As reported in the Partnership’s July 23, 2013 Form 8-K, effective October 1, 2013, Mr. Goldman was appointed President and Chief Executive Officer, succeeding Mr. Donovan who retired but will continue as an at will director. During fiscal 2013, Mr. Goldman served as the Partnership’s Executive Vice President and Chief Operating Officer.

(2) | Payable pursuant to the Partnership’s profit sharing pool, which is described under “Compensation Discussion and Analysis – Profit Sharing Allocation.”

(3) | The Partnership has two frozen defined benefit pension plans that we sometimes refer in this Report as the Petro defined benefit pension plan and the Meenan defined benefit pension plan, where participants are not accruing additional benefits. Mr. Ambury also participated in a tax-qualified supplemental employee retirement plan which prior to being frozen in 1997, represented contributions to an employee plan to compensate for a reduction in certain benefits prior to 1997. Included in Mr. Ambury’s amounts for the Change in Pension Value and Nonqualified Deferred Comp. Earnings are $0, $7,256 and $4,084 for fiscal years 2013, 2012 and 2011 respectively, for the actuarial changes in the value of his frozen supplemental employee retirement plan. The change in all the named executive’s pension values (including the supplemental employee retirement plan) are non-cash, and reflect normal adjustments resulting from changes in discount rates and government mandated mortality tables.

(4) | All other compensation is subdivided as follows:

Name |  | Management Incentive Compensation Plan |  |  | Company Match and Core Contribution to 401(K) Plan |  |  | Vacation Payout |  |  | Contributions to Nonqualified Deferred Compensation Plan |  |  | Car Allowance or Monetary Value for Personal Use of Company Owned Vehicle |  |  | Total |
Steven J. Goldman |  | $ | 32,261 |  |  | $ | 15,257 |  |  | $ | — |  |  |  | — |  |  | $ | 20,679 |  |  | $ | 68,197 |
Daniel P. Donovan |  | $ | 45,016 |  |  | $ | 15,285 |  |  | $ | 58,362 |  |  | $ | 71,035 |  |  | $ | 20,557 |  |  | $ | 210,255 |
Richard F. Ambury |  | $ | 35,263 |  |  | $ | 19,080 |  |  | $ | — |  |  |  | — |  |  | $ | 19,200 |  |  | $ | 73,543 |
Richard G. Oakley |  | $ | 6,002 |  |  | $ | 14,858 |  |  | $ | — |  |  |  | — |  |  | $ | 16,800 |  |  | $ | 37,660 |

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Grants of Plan-Based Awards

|  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | All Other Stocks Awards: Number of Shares of |  |  | All Other Option Awards: Number of Securities |  |  | Exercise or Base Price of Option |  |  | Grant Date Fair Value of Stock and |
|  |  |  |  | Estimated Future Payouts Equity Incentive Plan Awards (1) |  |  | Estimated Future Payouts Under Equity Incentive Plan |  |  |  |  |
Name |  | Grant Date (1) |  |  | Threshold ($) |  |  | Target ($) (2) |  |  | Maximum ($) |  |  | Threshold (#) |  |  | Target (#) |  |  | Maximum (#) |  |  | Stock or Units (#) |  |  | Underlying Options (#) |  |  | Awards ($/Sh) |  |  | Option Awards |
Steven J. Goldman |  |  | 7/21/09 |  |  |  | — |  |  | $ | 478,000 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Daniel P. Donovan |  |  | 7/21/09 |  |  |  | — |  |  | $ | 495,000 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Richard F. Ambury |  |  | 7/21/09 |  |  |  | — |  |  | $ | 483,000 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Richard G. Oakley |  |  | 7/21/09 |  |  |  | — |  |  | $ | 170,000 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |

(1) | On July 21, 2009, the Board of Directors authorized the continuance of the Partnership’s annual profit sharing plan, subject to its power to terminate the plan at any time. Profit sharing allocations are described under “Compensation Philosophy and Policies—Profit Sharing Allocations.”

(2) | The Partnership’s annual profit sharing plan does not provide for thresholds or maximums; the amounts listed represent the actual awards to the named executive officers for fiscal 2013.

Outstanding Equity Awards at Fiscal Year-End

None

Option Exercises and Stock Vested

None

Pension Plans Pursuant to Which Named Executive Officers Have an Accumulated Benefit But Are Not Currently Accruing Benefits

Name |  | Plan Name |  | Number of Years Credited Service |  |  | Present Value of Accumulated Benefit |  |  | Payments During Last Fiscal Year |
Steven J. Goldman (1) |  | Retirement Plan |  |  | — |  |  | $ | — |  |  | $ | — |
Daniel P. Donovan (1) |  | Retirement Plan |  |  | 21 |  |  | $ | 809,059 |  |  | $ | — |
Richard F. Ambury (1) |  | Retirement Plan |  |  | 13 |  |  | $ | 187,199 |  |  | $ | — |
|  | Supplemental Employee Retirement Plan |  |  | — |  |  | $ | 35,826 |  |  | $ | — |
Richard G. Oakley (1) |  | Retirement Plan |  |  | 19 |  |  | $ | 287,263 |  |  | $ | — |

The named executive officers have accumulated benefits in the tax-qualified Petro defined benefit pension plan that was frozen in 1997 or in the tax-qualified Meenan defined benefit pension plan that was frozen in 2002, subsequent to its combination with Petro. Mr. Ambury also participated in a tax-qualified supplemental employee retirement plan which, prior to being frozen in 1997, represented contributions to an employee plan to compensate for a reduction in certain benefits prior to 1997. Mr. Goldman was not a participant in any of these plans. Each year, the name executive officer’s accumulated benefits are actuarially calculated generally based on the credited years of service and each employee’s compensation at the time the plan was frozen. The present value of these amounts are the present value of a single life annuity generally payable at later or normal retirement age, adjusted for changes in discount rates and government mandated mortality tables. See note 12. Employee Benefit Plans, to the Partnership’s consolidated financial statements, for the material assumptions applied in quantifying the present value of the accumulated benefits of these frozen plans.

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Nonqualified Defined Contribution and Other Nonqualified Deferred Compensation Plans

|  | Nonqualified Deferred Compenstion |
|  | Executive |  |  | Registrant |  |  | Aggregate |  |  | Aggregate |  |  | Aggregate |
|  | Contributions |  |  | Contributions |  |  | Earnings |  |  | Withdrawals / |  |  | Balance at |
Name |  | In Last FY |  |  | In Last FY |  |  | In Last FY |  |  | Distributions |  |  | Last FYE |
Daniel P. Donovan (1) |  | $ | — |  |  | $ | 71,035 |  |  | $ | 7,368 |  |  | $ | — |  |  | $ | 168,019 |

(1) | Mr. Donovan is a participant in the Partnership’s frozen defined benefit pension plan and in fiscal year 2011 reached the plan’s full retirement age. In April 2011, the Board of Directors approved a deferred compensation arrangement to be funded by amounts which would have been payable to Mr. Donovan had he retired at age 65 and until his actual retirement. Mr. Donovan may not make withdrawals from the fund and amounts due to him will be payable upon his actual retirement. Aggregate earnings and losses reflect normal market fluctuations from investments in the fund. Contributions to the fund are included in the Summary Compensation Table. Mr. Donovan retired on September 30, 2013.

Potential Payments upon Termination

If Mr. Goldman’s employment is terminated by the Partnership for reasons other than for cause or if Mr. Goldman terminates his employment for good reason, he will be entitled to receive one-year’s salary as severance except in the case of a termination following a change in control which is discussed above under “Change in Control Agreements.” For 12 months following the termination of his employment, Mr. Goldman is prohibited from competing with the Partnership or from becoming involved either as an employee, as a consultant or in any other capacity, in the sale of heating oil or propane on a retail basis.

If Mr. Ambury’s employment is terminated for reasons other than cause or if Mr. Ambury terminates his employment for a good reason, he will be entitled to receive a severance payment of one year’s salary except in the case of a termination following a change in control which is discussed above under “Change in Control Agreements.” For 12 months following the termination of his employment, Mr. Ambury is prohibited from competing with the Partnership or from becoming involved either as an employee, as a consultant or in any other capacity, in the sale of heating oil or propane on a retail basis.

If Mr. Oakley’s employment is terminated by the Partnership without cause, he will be entitled to receive one-year’s salary as severance. For 12 months following the termination of his employment, Mr. Oakley is prohibited from competing with the Partnership or from becoming involved either as an employee, as a consultant or in any other capacity, in the sale of heating oil or propane on a retail basis.

The amounts shown in the table below assume that the triggering event for each named executive officer’s termination or change in control payment was effective as of the date of this report based upon their historical compensation arrangements as of such date. The actual amounts to be paid out can only be determined at the time of such named executive officer’s termination of employment or the Partnership’s change of control.

The employment agreements of the foregoing officers also require that they not reveal confidential information of the Partnership within twelve months following the termination of their employment.

|  | Potential Payments |  |  | Potential Payments Following |
Name |  | Upon Termination |  |  | a Change of Control |
Steven J. Goldman |  | $ | 360,000 |  |  | $ | 1,532,000 |
Richard F. Ambury |  | $ | 338,200 |  |  | $ | 1,520,400 |
Richard G. Oakley |  | $ | 224,500 |  |  | $ | — |

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##### Table of Contents

Compensation of Directors

|  | Director Compensation Table |
Name |  | Fees Earned or Paid in Cash |  |  | Unit Awards |  |  | Option Awards |  |  | Non-Equity Incentive Plan Compensation |  |  | Change in Pension Value and Nonqualified Deferred Compensation Earnings (6) |  |  | All Other Compensation (7) |  |  | Total |
Paul A. Vermylen, Jr. (1) |  | $ | 126,000 |  |  |  | — |  |  |  | — |  |  |  | — |  |  | $ | — |  |  | $ | 69,527 |  |  | $ | 195,527 |
Daniel P. Donovan (2) |  | $ | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Henry D. Babcock (3) |  | $ | 66,250 |  |  |  | — |  |  |  | — |  |  |  | — |  |  | $ | — |  |  | $ | — |  |  | $ | 66,250 |
C. Scott Baxter (3) |  | $ | 66,250 |  |  |  | — |  |  |  | — |  |  |  | — |  |  | $ | — |  |  | $ | — |  |  | $ | 66,250 |
Bryan H. Lawrence (4) |  | $ | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Sheldon B. Lubar |  | $ | 47,208 |  |  |  | — |  |  |  | — |  |  |  | — |  |  | $ | — |  |  | $ | — |  |  | $ | 47,208 |
William P. Nicoletti (5) |  | $ | 74,792 |  |  |  | — |  |  |  | — |  |  |  | — |  |  | $ | — |  |  | $ | — |  |  | $ | 74,792 |

(1) | Mr. Vermylen is non-executive Chairman of the Board.

(2) | Mr. Donovan was a management director until September 30, 2013 and the change in his pension value is included in the summary compensation table.

(3) | Mr. Babcock and Mr. Baxter are Audit Committee members.

(4) | Mr. Lawrence has chosen not to receive any fees as a director of the general partner of the Partnership.

(5) | Mr. Nicoletti is Chairman of the Audit Committee.

(6) | Mr. Vermylen participates in one of the Partnership’s frozen defined benefit pension plans. Participants are currently not accruing additional benefits under the frozen plan. The change in the pension value reflects normal non-cash adjustments resulting from changes in discount rates and government mandated mortality tables.

(7) | Mr. Vermylen is a participant in the Partnership’s frozen defined benefit pension plan and in fiscal year 2012 reached the plan’s full retirement age and started receiving pension payments.

Each non-management director receives an annual fee of $50,000 plus $1,500 for each regular and telephonic meeting attended. The Chairman of the Audit Committee receives an annual fee of $20,000 while other Audit Committee members receive an annual fee of $10,000. Each member of the Audit Committee receives $1,500 for every regular and telephonic meeting attended. The non-executive chairman of the Board receives an annual fee of $120,000.

ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table shows the beneficial ownership as of November 30, 2013 of common units and general partner units by:

(1) Kestrel and certain beneficial owners;

(2) each of the named executive officers and directors of Kestrel Heat;

(3) all directors and executive officers of Kestrel Heat as a group; and

(4) each person the Partnership knows to hold 5% or more of the Partnership’s units.

Except as indicated, the address of each person is c/o Star Gas Partners, L.P. at 2187 Atlantic Street, Stamford, Connecticut 06902-0011.

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##### Table of Contents

|  | Common Units |  |  | General Partner Units |
Name |  | Number |  |  | Percentage |  |  | Number |  |  | Percentage |
Kestrel (a) |  |  | 13,261,350 |  |  |  | 23.08 | % |  |  | 325,729 |  |  |  | 100.00 | %
Paul A. Vermylen, Jr. |  |  | 200,000 |  |  |  | * |  |  |  |  |  |  |  |  |
Sheldon B. Lubar |  |  | 200,000 |  |  |  | * |  |  |  |  |  |  |  |  |
Henry D. Babcock |  |  | 106,121 |  |  |  | * |  |  |  |  |  |  |  |  |
William P. Nicoletti |  |  | 35,506 |  |  |  | * |  |  |  |  |  |  |  |  |
Bryan H. Lawrence |  |  | — |  |  |  | — |  |  |  |  |  |  |  |  |
C. Scott Baxter |  |  | — |  |  |  | — |  |  |  |  |  |  |  |  |
Daniel P. Donovan |  |  | 25,000 |  |  |  | * |  |  |  |  |  |  |  |  |
Richard F. Ambury |  |  | 21,890 |  |  |  | * |  |  |  |  |  |  |  |  |
Steven J. Goldman |  |  | 19,500 |  |  |  | * |  |  |  |  |  |  |  |  |
Richard G. Oakley |  |  | — |  |  |  | — |  |  |  |  |  |  |  |  |
All officers and directors and Kestrel Heat, LLC as a group (11 persons) |  |  | 13,869,367 |  |  |  | 24.13 | % |  |  | 325,729 |  |  |  | 100.00 | %
Bandera Partners LLC (b) |  |  | 5,334,021 |  |  |  | 9.28 | % |  |  |  |  |  |  |  |

(a) | Includes (i) 500,000 common units and 325,729 general partner units owned by Kestrel Heat, and (ii) 12,761,350 common units owned by KM2, LLC, a Delaware limited liability company (“KM2”) as to which Kestrel, in its capacity as sole member of Kestrel Heat and KM2, may be deemed to share beneficial ownership.

(b) | According to a Form 13F filed by Bandera Partners LLC with the SEC on August 14, 2013.

* | Amount represents less than 1%.

ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The Partnership has a written conflict of interest policy and procedure that requires all officers, directors and employees to report to senior corporate management or the board of directors, all personal, financial or family interest in transactions that involve the individual and the Partnership. In addition, the Partnership Governance Guidelines provide that any monetary arrangement between a director and his or her affiliates (including any member of a director’s immediate family) and the Partnership or any of its affiliates for goods or services shall be subject to approval by the full Board of Directors.

The general partner does not receive any management fee or other compensation for its management of the Partnership. The general partner is reimbursed for all expenses incurred on behalf of the Partnership, including the cost of compensation, which is properly allocable to the Partnership. The Partnership’s Partnership Agreement provides that the general partner shall determine the expenses that are allocable to the Partnership in any reasonable manner determined by the general partner in its sole discretion. In addition, the general partner and its affiliates may provide services to the Partnership for which a reasonable fee would be charged as determined by the general partner.

Kestrel has the ability to elect the Board of Directors of Kestrel Heat, including Messrs. Vermylen, Lawrence and Lubar. Messrs. Vermylen, Lawrence and Lubar are also members of the board of managers of Kestrel and, either directly or through affiliated entities, own equity interests in Kestrel. Kestrel owns all of the issued and outstanding membership interests of Kestrel Heat and KM2.

Policies Regarding Transactions with Related Persons

Our Code of Business Conduct and Ethics, Partnership Governance Guidelines and Partnership Agreement set forth policies and procedures with respect to transactions with persons affiliated with the Partnership and the resolution of conflicts of interest, which taken together provide the Partnership with a framework for the review and approval of “transactions” with “related persons” as such terms are defined in Item 404 of regulation S-K.

For the years ended September 30, 2013, 2012, and 2011 the Partnership had no related party transactions or agreements pursuant to Item 404 of regulation S-K.

Our Code of Business Conduct and Ethics applies to our directors, officers, employees and their affiliates. It deals with conflicts of interest (e.g., transactions with the Partnership), confidential information, use of Partnership assets, business dealings, and other similar topics. The Code requires officers, directors and employees to avoid even the appearance of a conflict of interest and to report potential conflicts of interest to the Director of Internal Audit.

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Our Partnership Governance Guidelines provide that any monetary arrangement between a director and his or her affiliates (including any member of a director’s immediate family) and the Partnership or any of its affiliates for goods or services shall be subject to approval by the full Board of Directors. Although the Partnership Governance Guidelines by their terms only apply to directors the Board intends to apply this requirement to officers and employees and their affiliates.

To the extent that the Board determines that it would be in the best interests of the Partnership to enter into a transaction with a related person, the Board intends to utilize the procedures set forth in the Partnership Agreement for the review and approval of potential conflicts of interest. Our Partnership Agreement provides that whenever a potential conflict of interest exists or arises between the general partner or any of its Affiliates (including its directors, executive officers and controlling members), on the one hand, and the Partnership or any partner, on the other hand, any resolution or course of action in respect of such conflict of interest shall be permitted and deemed approved by all partners, and shall not constitute a breach of the Partnership Agreement, of any agreement contemplated therein, or of any duty stated or implied by law or equity, if the resolution or course of action is, or by operation of the Partnership Agreement is deemed to be, fair and reasonable to the Partnership.

Any conflict of interest and any resolution of such conflict of interest shall be conclusively deemed fair and reasonable to the Partnership if such conflict of interest or resolution is (i) approved by a committee of independent directors (the “Conflicts Committee”), (ii) on terms no less favorable to the Partnership than those generally being provided to or available from unrelated third parties or (iii) fair to the Partnership, taking into account the totality of the relationships between the parties involved (including other , transactions that may be particularly favorable or advantageous to the Partnership).

The general partner (including the Conflicts Committee) is authorized in connection with its determination of what is “fair and reasonable” to the Partnership and in connection with its resolution of any conflict of interest to consider:

| (A) | the relative interests of any party to such conflict, agreement, transaction or situation and the benefits and burdens relating to such interest;

| (B) | any customary or accepted industry practices and any customary or historical dealings with a particular person;

| (C) | any applicable generally accepted accounting practices or principles; and

| (D) | such additional factors as the general partner (including the Conflicts Committee) determines in its sole discretion to be relevant, reasonable or appropriate under the circumstances.

ITEM 14. | PRINCIPAL ACCOUNTANT FEES AND SERVICES

The following table represents the aggregate fees for professional audit services rendered by KPMG LLP including fees for the audit of the Partnership’s annual financial statements for the fiscal years 2013 and 2012, and for fees billed and accrued for other services rendered by KPMG LLP (in thousands).

|  | 2013 |  |  | 2012 |
Audit Fees(1) |  | $ | 1,495 |  |  | $ | 1,487 |
Tax Fees(2) |  |  | 496 |  |  |  | 322 |
Total Fees |  | $ | 1,991 |  |  | $ | 1,809 |

(1) | Audit fees were for professional services rendered in connection with audits and quarterly reviews of the consolidated financial statements of the Partnership. The fiscal 2012 amount includes $114,000 in audit fees, for services provided in fiscal 2011 but not paid until fiscal 2012, and for the comfort letter initiated in connection with a potential debt offering.

(2) | Tax fees related to services for tax consultation and tax compliance.

Audit Committee: Pre-Approval Policies and Procedures. At its regularly scheduled and special meetings, the Audit Committee of the Board of Directors considers and pre-approves any audit and non-audit services to be performed by the Partnership’s independent accountants. The Audit Committee has delegated to its chairman, an independent member of the Partnership’s Board of Directors, the authority to grant pre-approvals of non-audit services provided that the service(s) shall be reported to the Audit Committee at its next regularly scheduled meeting. On June 18, 2003, the Audit Committee adopted its pre-approval policies and procedures. Since that date, there have been no audit or non-audit services rendered by the Partnership’s principal accountants that were not pre-approved.

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PART IV

ITEM 15. | EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

1. Financial Statements—See “Index to Consolidated Financial Statements and Financial Statement Schedule” set forth on page F-1.

2. Financial Statement Schedule—See “Index to Consolidated Financial Statements and Financial Statement Schedule” set forth on page F-1.

3. Exhibits—See “Index to Exhibits” set forth on the following page.

INDEX TO EXHIBITS

Exhibit Number |  | Incorp by Ref. to Exh. |  | Description
3.1 |  | 3.1(1) |  | Amended and Restated Certificate of Limited Partnership
4.1 |  | 99.1(2) |  | Second Amended and Restated Agreement of Limited Partnership
4.2 |  | 99.3(3) |  | Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership
4.3 |  | 4.3(16) |  | Amendment No. 2 to Second Amended and Restated Agreement of Limited Partnership
4.4 |  | (20) |  | Amendment No. 3 to Second Amended and Restated Agreement of Limited Partnership
10.1 |  | 99.2(5) |  | Letter Agreement and general release dated March 7, 2005 between Star Gas Partners L.P. and Irik P. Sevin†
10.2 |  | 99.2(3) |  | Management Incentive Compensation Plan†
10.3 |  | (20) |  | Amended and Restated Management Incentive Compensation Plan†
10.4 |  | 99.4(3) |  | Form of Indemnification Agreement for Officers and Directors.
10.5 |  | (4) |  | Approved Dealer / Contractor Agreement dated as of July 11, 2006 by and between AFC First Financial Corporation and Petro Holdings, Inc.
10.6 |  | 99.4(7) |  | Form of Amendment No. 1 to Indemnification Agreement.
10.7 |  | (9) |  | Description of 2008 Profit Sharing Plan.†
10.8 |  | (10) |  | Employment Agreement dated December 3, 2007 between Star Gas Partners, L.P. and Steven J. Goldman.†
10.9 |  | (10) |  | Change in Control Agreement dated December 4, 2007 between Star Gas Partners, L.P. and Daniel P. Donovan.†
10.10 |  | (10) |  | Change in Control Agreement dated December 4, 2007 between Star Gas Partners, L.P. and Richard F. Ambury.†
10.11 |  | (11) |  | Employment Agreement dated April 28, 2008 between Star Gas Partners, L.P. and Richard Ambury†
10.12 |  | (13) |  | Agreement dated November 2, 2009 between Star Gas Partners, L.P. and Richard G. Oakley.†
10.13 |  | (14) |  | Champion Equity Purchase Agreement dated as of May 10, 2010.
10.14 |  | (15) |  | Employment Agreement dated as of November 8, 2010 between Star Gas Partners, L.P. and Daniel P. Donovan.
10.15 |  | 10.21(16) |  | Senior Notes Purchase Agreement, dated as of November 10, 2010, between Star Gas Partners, L.P., J.P. Morgan Securities LLC and RBS.
10.16 |  | 10.23(16) |  | Indenture dated as of November 16, 2010 for the 8.875% Senior Notes due 2017.
10.17 |  | 10.24(17) |  | Amended and Restated Revolving Credit Facility Agreement dated as of June 3, 2011.
10.18 |  | 10.25(17) |  | Amended and Restated Pledge Agreement dated as of June 3, 2011.
10.19 |  | (18) |  | First Amendment dated as of November 22, 2011 to Amended and Restated Revolving Credit Facility Agreement.
10.20 |  | (19) |  | Second Amendment dated as of April 6, 2012 to Amended and Restated Revolving Credit Facility Agreement.
10.21 |  | (21) |  | Letter Agreement, dated as of July 22, 2013, between the Partnership and Dan Donovan. †
10.22 |  | (21) |  | Letter Agreement, dated as of July 22, 2013, between the Partnership and Steven Goldman regarding employment.†
10.23 |  | (21) |  | Letter Agreement, dated as of July 22, 2013, between the Partnership and Steven Goldman regarding Change of Control.†
14 |  | (11) |  | Code of Business Conduct and Ethics
21 |  | * |  | Subsidiaries of the Registrant
23.1 |  | * |  | Consent of KPMG
31.1 |  | * |  | Certification of Chief Executive Officer, Star Gas Partners, L.P., pursuant to Rule 13a-14(a)/15d-14(a).(1)
31.2 |  | * |  | Certification of Chief Financial Officer, Star Gas Partners, L.P., pursuant to Rule 13a-14(a)/15d-14(a).(1)
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(1)
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(1)

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101.INS |  | * |  | XBRL Instance Document.
101.SCH |  | * |  | XBRL Taxonomy Extension Schema Document.
101.CAL |  | * |  | XBRL Taxonomy Extension Calculation Linkbase Document.
101.LAB |  | * |  | XBRL Taxonomy Extension Label Linkbase Document.
101.PRE |  | * |  | XBRL Taxonomy Extension Presentation Linkbase Document.
101.DEF |  | * |  | XBRL Taxonomy Extension Definition Linkbase Document.

* | Filed Herewith

† | Employee compensation plan.

(1) | Incorporated by reference to an exhibit to the Registrant’s Quarterly Report on Form 10-Q filed with the Commission on May 9, 2006.

(2) | Incorporated by reference to an exhibit to the Registrant’s Form 8-K dated April 28, 2006.

(3) | Incorporated by reference to an exhibit to the Registrant’s Form 8-K dated July 20, 2006.

(4) | Incorporated by reference to an exhibit to the Registrant’s Annual Report on Form 10-K for the fiscal year ended September 30, 2006, filed with the Commission on January 17, 2007.

(5) | Incorporated by reference to an exhibit to the Registrant’s Current Report on Form 8-K filed with the Commission on March 8, 2005.

(6) | Incorporated by reference to an exhibit to the Registrant’s Current Report on Form 8-K dated December 5, 2005.

(7) | Incorporated by reference to an exhibit to the Registrant’s Current Report on Form 8-K dated October 19, 2006.

(8) | [Intentionally Omitted]

(9) | Incorporated by reference to an exhibit to the Registrant’s Current Report on Form 8-K dated October 22, 2007.

(10) | Incorporated by reference to an exhibit to the Registrant’s Annual Report on Form 10-K for the fiscal year ended September 30, 2007 filed with the Commission on December 7, 2007.

(11) | Incorporated by reference to an exhibit to the Registrant’s Annual Report on Form 10-K for the fiscal year ended September 30, 2008 filed with the Commission on December 10, 2008.

(12) | [Intentionally Omitted]

(13) | Incorporated by reference to an exhibit to the Registrant’s Current Report on Form 8-K dated November 3, 2009.

(14) | Incorporated by reference to an exhibit to the Registrant’s Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2010.

(15) | Incorporated by reference to an exhibit to the Registrant’s Current Report on Form 8-K dated November 12, 2010.

(16) | Incorporated by reference to an exhibit to the Registrant’s Annual Report on Form 10-K for the fiscal year ended September 30, 2010.

(17) | Incorporated by reference to an exhibit to the Registrant’s Current Report on Form 8-K dated June 7, 2011.

(18) | Incorporated by reference to an exhibit to the Registrant’s Annual Report on Form 10-K for the fiscal year ended September 30, 2011.

(19) | Incorporated by reference to an exhibit to the Registrant’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2012.

(20) | Incorporated by reference to an exhibit to the Registrant’s Current Report on Form 8-K dated July 20, 2012.

(21) | Incorporated by reference to an exhibit to the Registrant’s Current Report on Form 8-K dated July 23, 2013.

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the general partner has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized:

STAR GAS PARTNERS, L.P.
By: |  | KESTREL HEAT, LLC (General Partner)
By: |  | /s/ Steven J. Goldman
|  | Steven J. Goldman
|  | President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons in the capacities and on the date indicated:

Signature |  |  |  | Title |  |  |  | Date
/s/ Steven J. Goldman Steven J. Goldman |  |  |  | President and Chief Executive Officer and Director Kestrel Heat, LLC |  |  |  | December 11, 2013
/s/ Richard F. Ambury Richard F. Ambury |  |  |  | Chief Financial Officer (Principal Financial Officer) Kestrel Heat, LLC |  |  |  | December 11, 2013
/s/ Richard G. Oakley Richard G. Oakley |  |  |  | Vice President—Controller (Principal Accounting Officer) Kestrel Heat, LLC |  |  |  | December 11, 2013
/s/ Paul A. Vermylen, Jr. Paul A. Vermylen, Jr. |  |  |  | Non-Executive Chairman of the Board and Director Kestrel Heat, LLC |  |  |  | December 11, 2013
/s/ Henry D. Babcock Henry D. Babcock |  |  |  | Director Kestrel Heat, LLC |  |  |  | December 11, 2013
/s/ C. Scott Baxter C. Scott Baxter |  |  |  | Director Kestrel Heat, LLC |  |  |  | December 11, 2013
/s/ Daniel P. Donovan Daniel P. Donovan |  |  |  | Director Kestrel Heat, LLC |  |  |  | December 11, 2013
/s/ Bryan H. Lawrence Bryan H. Lawrence |  |  |  | Director Kestrel Heat, LLC |  |  |  | December 11, 2013
/s/ Sheldon B. Lubar Sheldon B. Lubar |  |  |  | Director Kestrel Heat, LLC |  |  |  | December 11, 2013
/s/ William P. Nicoletti William P. Nicoletti |  |  |  | Director Kestrel Heat, LLC |  |  |  | December 11, 2013

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STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

AND FINANCIAL STATEMENT SCHEDULE

|  |  |  | Page
Part II Financial Information:
|  | Item 8—Financial Statements |  |
|  | Report of Independent Registered Public Accounting Firm |  | F-2
|  | Consolidated Balance Sheets as of September 30, 2013 and September 30, 2012 |  | F-3
|  | Consolidated Statements of Operations for the years ended September 30, 2013, September 30, 2012 and September 30, 2011 |  | F-4
|  | Consolidated Statements of Comprehensive Income for the years ended September 30, 2013, September 30, 2012 and September 30, 2011 |  | F-5
|  | Consolidated Statements of Partners’ Capital for the years ended September 30, 2013, September 30, 2012 and September 30, 2011 |  | F-6
|  | Consolidated Statements of Cash Flows for the years ended September 30, 2013, September 30, 2012 and September 30, 2011 |  | F-7
|  | Notes to Consolidated Financial Statements |  | F-8 – F-28
|  | Schedules for the years ended September 30, 2013, September 30, 2012 and September 30, 2011 |  |
|  | I. Condensed Financial Information of Registrant |  | F-29 – F-31
|  | II. Valuation and Qualifying Accounts |  | F-32
|  | All other schedules are omitted because they are not applicable or the required information is shown in the consolidated financial statements or the notes therein. |  |

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Report of Independent Registered Public Accounting Firm

The Partners of Star Gas Partners, L.P.:

We have audited the accompanying consolidated balance sheets of Star Gas Partners, L.P. and Subsidiaries (the “Partnership”) as of September 30, 2013 and 2012, and the related consolidated statements of operations, comprehensive income, partners’ capital and cash flows for each of the years in the three-year period ended September 30, 2013. In connection with our audits of the consolidated financial statements, we have also audited the financial statement schedules I and II listed in the accompanying index. We also have audited the Partnership’s internal control over financial reporting as of September 30, 2013, based on criteria established in Internal Control – Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership’s management is responsible for these consolidated financial statements and financial statement schedules, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedules and an opinion on the Partnership’s internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the consolidated financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Star Gas Partners, L.P. and Subsidiaries as of September 30, 2013 and 2012, and the results of its operations and its cash flows for each of the years in the three-year period ended September 30, 2013, in conformity with U.S. generally accepted accounting principles. In addition, in our opinion, the related financial statement schedules I and II listed in the accompanying index, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein. Also in our opinion, Star Gas Partners, L.P. and Subsidiaries maintained, in all material respects, effective internal control over financial reporting as of September 30, 2013, based on criteria established in Internal Control – Integrated Framework (1992) issued by COSO.

/s/ KPMG LLP

Stamford, Connecticut

December 11, 2013

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STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

|  | September 30, |
(in thousands) |  | 2013 |  |  | 2012 |
ASSETS |  |  |  |  |  |  |  |
Current assets |  |  |  |  |  |  |  |
Cash and cash equivalents |  | $ | 85,057 |  |  | $ | 108,091 |
Receivables, net of allowance of $7,928 and $6,886, respectively |  |  | 96,124 |  |  |  | 88,267 |
Inventories |  |  | 68,150 |  |  |  | 47,465 |
Fair asset value of derivative instruments |  |  | 646 |  |  |  | 5,004 |
Current deferred tax assets, net |  |  | 32,447 |  |  |  | 25,844 |
Prepaid expenses and other current assets |  |  | 23,456 |  |  |  | 26,848 |
Total current assets |  |  | 305,880 |  |  |  | 301,519 |
Property and equipment, net |  |  | 51,323 |  |  |  | 52,608 |
Goodwill |  |  | 201,130 |  |  |  | 201,103 |
Intangibles, net |  |  | 66,790 |  |  |  | 74,712 |
Deferred charges and other assets, net |  |  | 7,381 |  |  |  | 9,405 |
Total assets |  | $ | 632,504 |  |  | $ | 639,347 |
LIABILITIES AND PARTNERS’ CAPITAL |  |  |  |  |  |  |  |
Current liabilities |  |  |  |  |  |  |  |
Accounts payable |  | $ | 18,681 |  |  | $ | 22,583 |
Fair liability value of derivative instruments |  |  | 3,999 |  |  |  | 453 |
Accrued expenses and other current liabilities |  |  | 87,142 |  |  |  | 78,518 |
Unearned service contract revenue |  |  | 40,608 |  |  |  | 40,799 |
Customer credit balances |  |  | 70,196 |  |  |  | 85,976 |
Total current liabilities |  |  | 220,626 |  |  |  | 228,329 |
Long-term debt |  |  | 124,460 |  |  |  | 124,357 |
Long-term deferred tax liabilities, net |  |  | 19,292 |  |  |  | 8,436 |
Other long-term liabilities |  |  | 8,845 |  |  |  | 18,080 |
Partners’ capital |  |  |  |  |  |  |  |
Common unitholders |  |  | 282,289 |  |  |  | 286,819 |
General partner |  |  | 3 |  |  |  | 97 |
Accumulated other comprehensive loss, net of taxes |  |  | (23,011 | ) |  |  | (26,771 | )
Total partners’ capital |  |  | 259,281 |  |  |  | 260,145 |
Total liabilities and partners’ capital |  | $ | 632,504 |  |  | $ | 639,347 |

See accompanying notes to consolidated financial statements.

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STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

|  | Years Ended September 30, |
(in thousands, except per unit data) |  | 2013 |  |  | 2012 |  |  | 2011 |
Sales: |  |  |  |  |  |  |  |  |  |  |  |
Product |  | $ | 1,518,738 |  |  | $ | 1,295,374 |  |  | $ | 1,392,871 |
Installations and service |  |  | 223,058 |  |  |  | 202,214 |  |  |  | 198,439 |
Total sales |  |  | 1,741,796 |  |  |  | 1,497,588 |  |  |  | 1,591,310 |
Cost and expenses: |  |  |  |  |  |  |  |  |  |  |  |
Cost of product |  |  | 1,192,009 |  |  |  | 1,024,071 |  |  |  | 1,057,783 |
Cost of installations and service |  |  | 196,659 |  |  |  | 175,740 |  |  |  | 179,558 |
(Increase) decrease in the fair value of derivative instruments |  |  | 6,775 |  |  |  | (8,549 | ) |  |  | 2,567 |
Delivery and branch expenses |  |  | 250,210 |  |  |  | 217,376 |  |  |  | 250,762 |
Depreciation and amortization expenses |  |  | 17,303 |  |  |  | 16,395 |  |  |  | 17,884 |
General and administrative expenses |  |  | 18,356 |  |  |  | 18,689 |  |  |  | 20,709 |
Finance charge income |  |  | (5,521 | ) |  |  | (4,393 | ) |  |  | (4,814 | )
Operating income |  |  | 66,005 |  |  |  | 58,259 |  |  |  | 66,861 |
Interest expense, net |  |  | (14,433 | ) |  |  | (14,060 | ) |  |  | (15,654 | )
Amortization of debt issuance costs |  |  | (1,745 | ) |  |  | (1,634 | ) |  |  | (2,440 | )
Loss on redemption of debt |  |  | — |  |  |  | — |  |  |  | (1,700 | )
Income before income taxes |  |  | 49,827 |  |  |  | 42,565 |  |  |  | 47,067 |
Income tax expense |  |  | 19,921 |  |  |  | 16,576 |  |  |  | 22,723 |
Net income |  | $ | 29,906 |  |  | $ | 25,989 |  |  | $ | 24,344 |
General Partner’s interest in net income |  |  | 159 |  |  |  | 136 |  |  |  | 115 |
Limited Partners’ interest in net income |  | $ | 29,747 |  |  | $ | 25,853 |  |  | $ | 24,229 |
Basic and diluted income per Limited Partner Unit (1): |  | $ | 0.47 |  |  | $ | 0.40 |  |  | $ | 0.35 |
Weighted average number of Limited Partner units outstanding: |  |  |  |  |  |  |  |  |  |  |  |
Basic and Diluted |  |  | 59,409 |  |  |  | 61,931 |  |  |  | 66,822 |

(1) | See Note 17 Earnings Per Limited Partner Units.

See accompanying notes to consolidated financial statements.

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##### Table of Contents

STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

|  | Years Ended September 30, |
(in thousands) |  | 2013 |  |  | 2012 |  |  | 2011 |
Net income |  | $ | 29,906 |  |  | $ | 25,989 |  |  | $ | 24,344 |
Other comprehensive income: |  |  |  |  |  |  |  |  |  |  |  |
Unrealized gain on pension plan obligation (1) |  |  | 6,337 |  |  |  | 1,176 |  |  |  | 171 |
Tax effect of unrealized gain on pension plan obligation |  |  | (2,577 | ) |  |  | (480 | ) |  |  | (167 | )
Total other comprehensive income |  |  | 3,760 |  |  |  | 696 |  |  |  | 4 |
Total comprehensive income |  | $ | 33,666 |  |  | $ | 26,685 |  |  | $ | 24,348 |

(1) | These items are included in the computation of net periodic pension cost. See Note 12—Employee Benefit Plan.

See accompanying notes to consolidated financial statements.

F-5

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STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

Years Ended September 30, 2013, 2012 and 2011

|  | Number of Units |  |  |  |  |  |  |  |  |  |  |  |  |
(in thousands) |  | Common |  |  | General Partner |  |  | Common |  |  | General Partner |  |  | Accum. Other Comprehensive Income (Loss) |  |  | Total Partners’ Capital |
Balance as of September 30, 2010 |  |  | 67,078 |  |  |  | 326 |  |  | $ | 307,092 |  |  | $ | 290 |  |  | $ | (27,471 | ) |  | $ | 279,911 |
Net income |  |  |  |  |  |  |  |  |  |  | 24,229 |  |  |  | 115 |  |  |  |  |  |  |  | 24,344 |
Unrealized gain on pension plan obligation (1) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 171 |  |  |  | 171 |
Tax effect of unrealized gain on pension plan obligation |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (167 | ) |  |  | (167 | )
Distributions (2) |  |  |  |  |  |  |  |  |  |  | (20,459 | ) |  |  | (218 | ) |  |  |  |  |  |  | (20,677 | )
Retirement of units (3) |  |  | (2,108 | ) |  |  |  |  |  |  | (10,949 | ) |  |  |  |  |  |  |  |  |  |  | (10,949 | )
Balance as of September 30, 2011 |  |  | 64,970 |  |  |  | 326 |  |  | $ | 299,913 |  |  | $ | 187 |  |  | $ | (27,467 | ) |  | $ | 272,633 |
Net income |  |  |  |  |  |  |  |  |  |  | 25,853 |  |  |  | 136 |  |  |  |  |  |  |  | 25,989 |
Unrealized gain on pension plan obligation (1) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1,176 |  |  |  | 1,176 |
Tax effect of unrealized gain on pension plan obligation |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (480 | ) |  |  | (480 | )
Distributions (2) |  |  |  |  |  |  |  |  |  |  | (19,299 | ) |  |  | (226 | ) |  |  |  |  |  |  | (19,525 | )
Retirement of units (3) |  |  | (3,968 | ) |  |  |  |  |  |  | (19,648 | ) |  |  |  |  |  |  |  |  |  |  | (19,648 | )
Balance as of September 30, 2012 |  |  | 61,002 |  |  |  | 326 |  |  | $ | 286,819 |  |  | $ | 97 |  |  | $ | (26,771 | ) |  | $ | 260,145 |
Net income |  |  |  |  |  |  |  |  |  |  | 29,747 |  |  |  | 159 |  |  |  |  |  |  |  | 29,906 |
Unrealized gain on pension plan obligation (1) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 6,337 |  |  |  | 6,337 |
Tax effect of unrealized gain on pension plan obligation |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (2,577 | ) |  |  | (2,577 | )
Distributions (2) |  |  |  |  |  |  |  |  |  |  | (19,060 | ) |  |  | (253 | ) |  |  |  |  |  |  | (19,313 | )
Retirement of units (3) |  |  | (3,284 | ) |  |  |  |  |  |  | (15,217 | ) |  |  |  |  |  |  |  |  |  |  | (15,217 | )
Balance as of September 30, 2013 |  |  | 57,718 |  |  |  | 326 |  |  | $ | 282,289 |  |  | $ | 3 |  |  | $ | (23,011 | ) |  | $ | 259,281 |

(1) | These items are included in the computation of net periodic pension cost. See Note 12—Employee Benefit Plan.

(2) | See Note 3—Quarterly Distributions of Available Cash.

(3) | See Note 4—Common Unit Repurchase and Retirement.

See accompanying notes to consolidated financial statements.

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STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

|  | Years Ended September 30, |
(in thousands) |  | 2013 |  |  | 2012 |  |  | 2011 |
Cash flows provided by (used in) operating activities: |  |  |  |  |  |  |  |  |  |  |  |
Net income |  | $ | 29,906 |  |  | $ | 25,989 |  |  | $ | 24,344 |
Adjustments to reconcile net income to net cash provided by (used in) operating activities: |  |  |  |  |  |  |  |  |  |  |  |
(Increase) decrease in fair value of derivative instruments |  |  | 6,775 |  |  |  | (8,549 | ) |  |  | 2,567 |
Depreciation and amortization |  |  | 19,047 |  |  |  | 18,029 |  |  |  | 20,324 |
Loss on redemption of debt |  |  | — |  |  |  | — |  |  |  | 1,700 |
Provision for losses on accounts receivable |  |  | 6,481 |  |  |  | 6,017 |  |  |  | 10,388 |
Change in deferred taxes |  |  | 1,676 |  |  |  | 12,913 |  |  |  | 15,831 |
Changes in operating assets and liabilities net of amounts related to acquisitions: |  |  |  |  |  |  |  |  |  |  |  |
(Increase) decrease in receivables |  |  | (14,074 | ) |  |  | 5,804 |  |  |  | (31,593 | )
(Increase) decrease in inventories |  |  | (20,664 | ) |  |  | 34,335 |  |  |  | (13,189 | )
Decrease in other assets |  |  | 4,207 |  |  |  | 4,226 |  |  |  | 1,594 |
Increase (decrease) in accounts payable |  |  | (4,555 | ) |  |  | 3,372 |  |  |  | 1,943 |
Increase (decrease) in customer credit balances |  |  | (15,878 | ) |  |  | 11,952 |  |  |  | (1,776 | )
Increase (decrease) in other current and long-term liabilities |  |  | 5,571 |  |  |  | (8,260 | ) |  |  | 7,269 |
Net cash provided by operating activities |  |  | 18,492 |  |  |  | 105,828 |  |  |  | 39,402 |
Cash flows provided by (used in) investing activities: |  |  |  |  |  |  |  |  |  |  |  |
Capital expenditures |  |  | (5,994 | ) |  |  | (5,803 | ) |  |  | (6,361 | )
Proceeds from sales of fixed assets |  |  | 410 |  |  |  | 503 |  |  |  | 92 |
Acquisitions |  |  | (1,376 | ) |  |  | (39,217 | ) |  |  | (9,659 | )
Net cash used in investing activities |  |  | (6,960 | ) |  |  | (44,517 | ) |  |  | (15,928 | )
Cash flows provided by (used in) financing activities: |  |  |  |  |  |  |  |  |  |  |  |
Revolving credit facility borrowings |  |  | 111,542 |  |  |  | 86,252 |  |  |  | 88,416 |
Revolving credit facility repayments |  |  | (111,542 | ) |  |  | (86,252 | ) |  |  | (88,416 | )
Repayment of debt |  |  | — |  |  |  | — |  |  |  | (82,499 | )
Proceeds from the issuance of debt |  |  | — |  |  |  | — |  |  |  | 124,188 |
Debt extinguishment costs |  |  | — |  |  |  | — |  |  |  | (1,409 | )
Distributions |  |  | (19,313 | ) |  |  | (19,525 | ) |  |  | (20,677 | )
Unit repurchase |  |  | (15,217 | ) |  |  | (19,648 | ) |  |  | (10,949 | )
Increase in deferred charges |  |  | (36 | ) |  |  | (836 | ) |  |  | (6,401 | )
Net cash provided by (used in) financing activities |  |  | (34,566 | ) |  |  | (40,009 | ) |  |  | 2,253 |
Net increase (decrease) in cash |  |  | (23,034 | ) |  |  | 21,302 |  |  |  | 25,727 |
Cash and equivalents at beginning of period |  |  | 108,091 |  |  |  | 86,789 |  |  |  | 61,062 |
Cash and equivalents at end of period |  | $ | 85,057 |  |  | $ | 108,091 |  |  | $ | 86,789 |

See accompanying notes to consolidated financial statements.

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STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1) Partnership Organization

Star Gas Partners, L.P. (“Star Gas Partners,” the “Partnership,” “we,” “us,” or “our”) is a home heating oil and propane distributor and services provider with one reportable operating segment that principally provides services to residential and commercial customers to heat their homes and buildings. Star Gas Partners is a master limited partnership, which at September 30, 2013, had outstanding 57.7 million common units (NYSE: “SGU”) representing 99.44% limited partner interest in Star Gas Partners, and 0.3 million general partner units, representing 0.56% general partner interest in Star Gas Partners.

The Partnership is organized as follows:

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

| • |  | The Partnership’s operations are conducted through Petro Holdings, Inc. and its subsidiaries (“Petro”). Petro is a Minnesota corporation that is an indirect wholly-owned subsidiary of the Partnership. Petro is subject to Federal and state corporation income taxes. Petro is a Northeast and Mid-Atlantic region retail distributor of home heating oil and propane that at September 30, 2013 served approximately 404,000 full-service residential and commercial home heating oil and propane customers. Petro also sold home heating oil, gasoline and diesel fuel to approximately 54,000 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 15,700 customers.

| • |  | Star Gas Finance Company is a 100% owned subsidiary of the Partnership. Star Gas Finance Company serves as the co-issuer, jointly and severally with the Partnership, of its $125 million (excluding discount) 8.875% Senior Notes outstanding at September 30, 2013, that are due 2017. The Partnership is dependent on distributions, including inter-company interest payments from its subsidiaries, to service the Partnership’s debt obligations. The distributions from the Partnership’s subsidiaries are not guaranteed and are subject to certain loan restrictions. Star Gas Finance Company has nominal assets and conducts no business operations. (See Note 11—Long-Term Debt and Bank Facility Borrowings)

2) Summary of Significant Accounting Policies

Basis of Presentation

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

Reclassification

The accompanying September 30, 2012 and 2011 consolidated statements of operations have been revised from their previous presentation to reclassify finance charge income of $4,393 and $4,814, respectively and present it separately as an element of operating income. Previously, finance charge income was included in the caption interest income in the consolidated statements of operations. This reclassification was made in order to conform with common industry practice regarding the reporting of finance charge income in operating income, and had no impact on net income, financial position, and cash flows for any period. As a result, interest expense, net consists of:

(in thousands) |  | September 30, |
|  | 2013 |  |  | 2012 |  |  | 2011 |
Interest expense |  | $ | (14,474 | ) |  | $ | (14,110 | ) |  | $ | (15,710 | )
Interest income |  |  | 41 |  |  |  | 50 |  |  |  | 56 |
Interest expense, net |  | $ | (14,433 | ) |  | $ | (14,060 | ) |  | $ | (15,654 | )

Comprehensive Income

Comprehensive income is comprised of net income and other comprehensive income. Other comprehensive income 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.

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Use of Estimates

The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.

Revenue Recognition

Sales of heating oil and other fuels are recognized at the time of delivery of the product to the customer and sales of heating and air conditioning equipment are recognized at the time of installation. Revenue from repairs and maintenance service is recognized upon completion of the service. Payments received from customers for equipment service contracts are deferred and amortized into income over the terms of the respective service contracts, on a straight-line basis, which generally do not exceed one year. To the extent that the Partnership anticipates that future costs for fulfilling its contractual obligations under its service maintenance contracts will exceed the amount of deferred revenue currently attributable to these contracts, the Partnership recognizes a loss in current period earnings equal to the amount that anticipated future costs exceed related deferred revenues.

Cost of Product

Cost of product includes the cost of heating oil, diesel, propane, kerosene, heavy oil, gasoline, throughput costs, barging costs, option costs, and realized gains/losses on closed derivative positions for product sales.

Cost of Installations and Service

Cost of installations and service includes equipment and material costs, wages and benefits for equipment technicians, dispatchers and other support personnel, subcontractor expenses, commissions and vehicle related costs.

Delivery and Branch Expenses

Delivery and branch expenses include wages and benefits and department related costs for drivers, dispatchers, garage mechanics, customer service, sales and marketing, compliance, credit and branch accounting, information technology, insurance, weather hedge contract costs and recoveries, and operational support.

General and Administrative Expenses

General and administrative expenses include wages and benefits and department related costs for human resources, finance and partnership accounting, administrative support and supply.

Receivables and Allowance for Doubtful Accounts

Accounts receivables from customers are recorded at the invoiced amounts. Finance charges may be applied to trade receivables that are more than 30 days past due, and are recorded as finance charge income.

The allowance for doubtful accounts is the Partnership’s best estimate of the amount of trade receivables that may not be collectible. The allowance is determined at an aggregate level by grouping accounts based on the type of account and its receivable aging. The allowance is based on both quantitative and qualitative factors, including historical loss experience, historical collection patterns, overdue status, aging trends, and current economic conditions. The Partnership has an established process to periodically review current and past due trade receivable balances to determine the adequacy of the allowance. No single statistic or measurement determines the adequacy of the allowance. The total allowance reflects management’s estimate of losses inherent in its trade receivables at the balance sheet date. Different assumptions or changes in economic conditions could result in material changes to the allowance for doubtful accounts.

Allocation of Net Income

Net income for partners’ capital and statement of operations is allocated to the general partner and the limited partners in accordance with their respective ownership percentages, after giving effect to cash distributions paid to the general partner in excess of its ownership interest, if any.

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Net Income per Limited Partner Unit

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

Cash, Accounts Receivable, Notes Receivable, Revolving Credit Facility Borrowings, and Accounts Payable

The carrying amount of cash, accounts receivable, notes receivable, revolving credit facility borrowings, and accounts payable approximates fair value because of the short maturity of these instruments.

Cash Equivalents

The Partnership considers all highly liquid investments with an original maturity of three months or less, when purchased, to be cash equivalents.

Inventories

Liquid product inventories are stated at the lower of cost or market using the weighted average cost method of accounting. All other inventories, representing parts and equipment are stated at the lower of cost or market using the FIFO method.

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.

Goodwill and Intangible Assets

Goodwill and intangible assets include goodwill, customer lists, trade names and covenants not to compete.

Goodwill is the excess of cost over the fair value of net assets in the acquisition of a company. In accordance with FASB ASC 350-10-05 Intangibles-Goodwill and Other, goodwill and intangible assets with indefinite useful lives are not amortized, but instead are annually tested for impairment. Also in accordance with this standard, intangible assets with finite useful lives are amortized over their respective estimated useful lives to their estimated residual values, and reviewed for impairment. The Partnership performs its annual impairment review during its fiscal fourth quarter or more frequently if events or circumstances indicate that the value of goodwill might be impaired.

Customer lists are the names and addresses of an acquired company’s customers. Based on historical retention experience, these lists are amortized on a straight-line basis over seven to ten years.

Trade names are the names of acquired companies. Based on the economic benefit expected and historical retention experience of customers, trade names are amortized on a straight-line basis over seven to twenty years.

Covenants not to compete are agreements with the owners of acquired companies and are amortized over the respective lives of the covenants on a straight-line basis, which are generally five years.

Business Combinations

The Partnership uses the acquisition method of accounting in accordance with FASB ASC 805 Business Combinations. The acquisition method of accounting requires the Partnership to use significant estimates and assumptions, including fair value estimates, as of the business combination date, and to refine those estimates as necessary during the measurement period (defined as the period, not to exceed one year, in which the amounts recognized for a business combination may be adjusted). Each acquired company’s operating results are included in the Partnership’s consolidated financial statements starting on the date of acquisition. The purchase price is equivalent to the fair value of consideration transferred. Tangible and identifiable intangible assets acquired and liabilities assumed as of the date of acquisition are recorded at the acquisition date fair value. The separately identifiable intangible assets generally are comprised of customer lists, trade names and covenants not to compete. Goodwill is recognized for the excess of the purchase price over the net fair value of assets acquired and liabilities assumed.

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Costs that are incurred to complete the business combination such as investment banking, legal and other professional fees are not considered part of consideration transferred, and are charged to general and administrative expense as they are incurred. For any given acquisition, certain contingent consideration may be identified. Estimates of the fair value of liability or asset classified contingent consideration are included under the acquisition method as part of the assets acquired or liabilities assumed. At each reporting date, these estimates are remeasured to fair value, with changes recognized in earnings.

Impairment of Long-lived Assets

The Partnership reviews intangible assets and other long-lived assets in accordance with FASB ASC 360-10-05-4 Property Plant and Equipment, Impairment or Disposal of Long-Lived Assets subsection, for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. The Partnership determines whether the carrying values of such assets are recoverable over their remaining estimated lives through undiscounted future cash flow analysis. If such a review should indicate that the carrying amount of the assets is not recoverable, the Partnership will reduce the carrying amount of such assets to fair value.

Deferred Charges

Deferred charges represent the costs associated with the issuance of debt instruments and are amortized over the lives of the related debt instruments.

Advertising and Direct Mail Expenses

Advertising and direct mail costs are expensed as they are incurred. Advertising and direct mail expenses were $10.5 million, $9.6 million, and $9.5 million, in 2013, 2012, and 2011, respectively and are recorded in delivery and branch expenses.

Customer Credit Balances

Customer credit balances represent payments received in advance from customers pursuant to a balanced payment plan (whereby customers pay on a fixed monthly basis) and the payments made have exceeded the charges for liquid product and other services.

Environmental Costs

Costs associated with managing hazardous substances and pollution are expensed on a current basis. Accruals are made for costs associated with the remediation of environmental pollution when it becomes probable that a liability has been incurred and the amount can be reasonably estimated.

Insurance Reserves

The Partnership uses a combination of insurance, self-insured retention and self-insurance for a number of risks, including workers’ compensation, general liability, vehicle liability and property. Reserves are established and periodically evaluated, based upon expectations as to what our ultimate liability may be for outstanding claims using developmental factors based upon historical claim experience, including frequency, severity, demographic factors and other actuarial assumptions, supplemented with support from qualified actuaries.

Income Taxes

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

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

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

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Sales, Use and Value Added Taxes

Taxes are assessed by various governmental authorities on many different types of transactions. Sales reported for product, installation and service excludes taxes.

Derivatives and Hedging

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. The Partnership has elected not to designate its derivative instruments as hedging instruments under this guidance, and the changes in fair value of the derivative instruments are recognized in our statement of operations.

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 FASB 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.

In July 2012, the Partnership entered into a weather hedge contract for the fiscal years September 30, 2013, 2014 and 2015 with Swiss Re Financial Products Corporation, under which we are entitled to receive a payment of $35,000 per heating degree-day shortfall, if the total number of heating degree-days in the period covered is less than 92.5% of the ten year average (the “Payment Threshold”). The hedge covers the period from November 1 through March 31, taken as a whole, for each respective fiscal year and has a maximum payout of $12.5 million for each fiscal year.

Recent Accounting Pronouncements

In fiscal 2013, the provisions of FASB ASU No. 2011-08, Intangibles-Goodwill and Other (350): Testing Goodwill for Impairment became effective. This standard simplifies how entities test goodwill for impairment by providing for an optional qualitative assessment in determining whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount, as a basis for determining whether it is necessary to perform the first step, of the two-step goodwill impairment test. We did not elect to perform the optional qualitative test in fiscal 2013.

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

3) Quarterly Distribution of Available Cash

The Partnership agreement provides that beginning October 1, 2008, minimum quarterly distributions on the common units will start accruing at the rate of $0.0675 per quarter ($0.27 on an annual basis) in accordance with the Partnership agreement. There were no distributions of available cash by us before February 2009. Thereafter, in general, the Partnership intends to distribute to its partners on a quarterly basis, all of its available cash, if any, in the manner described below. “Available cash” generally means, for any of its fiscal quarters, all cash on hand at the end of that quarter, less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the general partners to:

| • |  | provide for the proper conduct of the Partnership’s business including acquisitions and debt payments;

| • |  | comply with applicable law, any of its debt instruments or other agreements; or

| • |  | provide funds for distributions to the common unitholders during the next four quarters, in some circumstances.

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Available cash will generally be distributed as follows:

| • |  | first, 100% to the common units, pro rata, until the Partnership distributes to each common unit the minimum quarterly distribution of $0.0675;

| • |  | second, 100% to the common units, pro rata, until the Partnership distributes to each common unit any arrearages in payment of the minimum quarterly distribution on the common units for prior quarters;

| • |  | third, 100% to the general partner units, pro rata, until the Partnership distributes to each general partner unit the minimum quarterly distribution of $0.0675;

| • |  | fourth, 90% to the common units, pro rata, and 10% to the general partner units, pro rata (subject to the Management Incentive Plan), until the Partnership distributes to each common unit the first target distribution of $0.1125; and

| • |  | thereafter, 80% to the common units, pro rata, and 20% to the general partner units, pro rata.

The Partnership is obligated to meet certain financial covenants under the amended and restated revolving credit facility. The Partnership must maintain excess availability of at least 17.5% of the revolving commitment then in effect and a fixed charge coverage ratio of 1.15 in order to make any distributions to unitholders.

For fiscal 2013, 2012, and 2011, cash distributions declared per common unit were $0.320, $0.310, and $0.305, respectively.

For fiscal 2013, 2012, and 2011, $0.2 million, $0.1 million, and $0.1 million, respectively, of incentive distributions were paid to the general partner, exclusive of amounts paid subject to the Management Incentive Plan.

4) Common Unit Repurchase Plans and Retirement

In fiscal 2010, the Partnership concluded its Plan I common units repurchase program and retired at an average price paid of $4.04 per unit, all 7.5 million common units authorized for repurchase.

In fiscal 2012, the Partnership concluded its Plan II common units repurchase program and retired at an average price paid of $4.94 per unit, all 7.25 million common units authorized for repurchase.

In July 2012, the Board authorized the repurchase of up to 3.0 million of the Partnership’s common units (“Plan III”). In July 2013, the Board authorized an additional 1.9 million common units to be repurchased under its Plan III common unit repurchase plan. The authorized common unit repurchases may be made from time-to-time in the open market, in privately negotiated transactions or in such other manner deemed appropriate by management. There is no guarantee of the exact number of units that will be purchased under the program and the Partnership may discontinue purchases at any time. The program does not have a time limit. In June 2013, the Board authorized the repurchase of 1.15 million additional common units in a private transaction. The Partnership’s repurchase activities take into account SEC safe harbor rules and guidance for issuer repurchases. All of the common units purchased in the repurchase program will be retired.

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

(in thousands, except per unit amounts) |  |  |  |  |  |  |  |  |
Period |  | Total Number of Units Purchased as Part of a Publicly Announced Plan or Program |  |  | Average Price Paid per Unit (a) |  |  | Maximum Number of Units that May Yet Be Purchased Under the Program |
Plan III - Number of units authorized |  |  |  |  |  |  |  |  |  |  | 4,894 |
Private transaction - Number of units authorized (b) |  |  |  |  |  |  |  |  |  |  | 1,150 |
|  |  |  |  |  |  |  |  |  |  | 6,044 |
Plan III - Fiscal year 2012 total |  |  | 22 |  |  | $ | 4.26 |  |  |  | 6,022 |
Plan III - First quarter fiscal year 2013 total |  |  | 1,015 |  |  | $ | 4.18 |  |  |  | 5,007 |
Plan III - Second quarter fiscal year 2013 total |  |  | 310 |  |  | $ | 4.36 |  |  |  | 4,697 |
Plan III - Third quarter fiscal year 2013 total (b) |  |  | 1,697 |  |  | $ | 4.92 |  |  |  | 3,000 |
Plan III - July 2013 |  |  | — |  |  | $ | — |  |  |  | 3,000 |
Plan III - August 2013 |  |  | 120 |  |  | $ | 4.87 |  |  |  | 2,880 |
Plan III - September 2013 |  |  | 142 |  |  | $ | 4.84 |  |  |  | 2,738 |
Plan III - Fourth quarter fiscal year 2013 total |  |  | 262 |  |  | $ | 4.85 |  |  |  | 2,738 |
Plan III - Fiscal year 2013 total |  |  | 3,284 |  |  | $ | 4.63 |  |  |  | 2,738 |

(a) | Amounts include repurchase costs.

(b) | Third quarter fiscal 2013 common unit repurchases include 1.15 million common units acquired in a private transaction.

5) Derivatives and Hedging—Disclosures and Fair Value Measurements

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

To hedge a substantial majority of the purchase price associated with heating oil gallons anticipated to be sold to its price-protected customers as of September 30, 2013, the Partnership held 2.4 million gallons of physical inventory and had bought 6.0 million gallons of swap contracts with a notional value of $18.0 million and a fair value of $(0.2) million, 2.9 million gallons of call options with a notional value of $10.6 million and a fair value of $0.02 million, 5.0 million gallons of put options with a notional value of $11.8 million and a fair value of $0.04 million and 81.2 million net gallons of synthetic calls with a notional value of $252.8 million and a fair value of $(15.9) million, all in future months to match anticipated sales. To hedge the inter-month differentials for its price-protected customers, its physical inventory on hand and inventory in transit, the Partnership, as of September 30, 2013, had bought 17.4 million gallons of future contracts with a notional value of $51.9 million and a fair value of $(0.6) million, had sold 26.4 million gallons of future contracts with a notional value of $78.9 million and a fair value of $1.2 million and had sold 8.5 million gallons of future swap contracts with a notional value of $24.9 million and a fair value of $(0.3) million. To hedge high sulfur home heating oil gallons anticipated to be sold in future months, the Partnership as of September 30, 2013, had bought corresponding long and short 28.2 million net gallons of swap contracts with a notional value of $83.8 million and a fair value of $0.7 million and bought 6.0 million gallons of spread contracts (simultaneous long and short positions) with a notional value of $(0.5) million and a fair value of $0.1 million. To hedge a majority of its internal fuel usage for fiscal 2013, the Partnership as of September 30, 2013, had bought 3.2 million gallons of future swap contracts with a notional value of $9.0 million and a fair value of $0.05 million.

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To hedge a substantial majority of the purchase price associated with heating oil gallons anticipated to be sold to its price-protected customers as of September 30, 2012, the Partnership held 3.3 million gallons of physical inventory and had bought 7.1 million gallons of swap contracts with a notional value of $21.1 million and a fair value of $0.8 million, 2.8 million gallons of call options with a notional value of $10.0 million and a fair value of $0.1 million, 6.8 million gallons of put options with a notional value of $16.1 million and a fair value of $0.1 million and 75.2 million net gallons of synthetic calls with a notional value of $237.5 million and a fair value of $3.7 million, all in future months to match anticipated sales. To hedge the inter-month differentials for its price-protected customers, its physical inventory on hand and inventory in transit, the Partnership, as of September 30, 2012, had bought 22.6 million gallons of future contracts with a notional value of $67.6 million and a fair value of $1.7 million, had sold 26.7 million gallons of future contracts with a notional value of $80.3 million and a fair value of $(1.9) million, had bought 19.2 million gallons of future swap contracts with a notional value of $60.6 million and a fair value of $(0.4) million and had sold 24.3 million gallons of future swap contracts with a notional value of $75.3 million and a fair value of $(0.3) million. To hedge a majority of its internal fuel usage for fiscal 2012, the Partnership as of September 30, 2012, had bought 2.2 million gallons of future swap contracts with a notional value of $5.7 million and a fair value of $0.6 million.

The Partnership’s derivative instruments are with the following counterparties: Bank of America, N.A., Bank of Montreal, Cargill, Inc., JPMorgan Chase Bank, N.A., Key Bank, N.A., Regions Financial Corporation, Societe Generale, and Wells Fargo Bank, N.A. The Partnership assesses counterparty credit risk and maintains master netting arrangements with counterparties to help manage the risks, and record derivative positions on a net basis. The Partnership considers counterparty credit risk to be low. At September 30, 2013, the aggregate cash posted as collateral in the normal course of business at counterparties was $1.1 million. Positions with counterparties who are also parties to our revolving credit facility are collateralized under that facility. As of September 30, 2013, $10.5 million of hedge positions were secured under the credit facility.

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

FASB ASC 820-10 Fair Value Measurements and Disclosures, established a three-tier fair value hierarchy, which classified the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices for identical instruments in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. The Partnership’s Level 1 derivative assets and liabilities represent the fair value of commodity contracts used in its hedging activities that are identical and traded in active markets. The Partnership’s Level 2 derivative assets and liabilities represent the fair value of commodity contracts used in its hedging activities that are valued using either directly or indirectly observable inputs, whose nature, risk and class are similar. No significant transfers of assets or liabilities have been made into and out of the Level 1 or Level 2 tiers. All derivative instruments were non-trading positions and were either a Level 1 or Level 2 instrument. The fair market value of our Level 1 and Level 2 derivative assets and liabilities are calculated by our counter-parties and are independently validated by the Partnership. The Partnership’s calculations are, for Level 1 derivative assets and liabilities, based on the published New York Mercantile Exchange (“NYMEX”) market prices for the commodity contracts open at the end of the period. For Level 2 derivative assets and liabilities the calculations performed by the Partnership are based on a combination of the NYMEX published market prices and other inputs, including such factors as present value, volatility and duration.

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The Partnership had no assets or liabilities that are measured at fair value on a nonrecurring basis subsequent to their initial recognition. The Partnership’s financial assets and liabilities measured at fair value on a recurring basis are listed on the following table.

(In thousands) |  |  |  |  |  |  | Fair Value Measurements at Reporting Date Using: |
Derivatives Not Designated as Hedging Instruments Under FASB ASC 815-10 |  | Balance Sheet Location |  | Total |  |  | Quoted Prices in Active Markets for Identical Assets Level 1 |  |  | Significant Other Observable Inputs Level 2 |  |  | Significant Unobservable Inputs Level 3 |
Asset Derivatives at September 30, 2013 |
Commodity contracts |  | Fair asset and fair liability value of derivative instruments |  | $ | 14,467 |  |  | $ | 1,175 |  |  | $ | 13,292 |  |  | $ | — |
Commodity contract assets at September 30, 2013 |  | $ | 14,467 |  |  | $ | 1,175 |  |  | $ | 13,292 |  |  | $ | — |
Liability Derivatives at September 30, 2013 |
Commodity contracts |  | Fair liability and fair asset value of derivative instruments |  | $ | (17,820 | ) |  | $ | (519 | ) |  | $ | (17,301 | ) |  | $ | — |
Commodity contract liabilities at September 30, 2013 |  | $ | (17,820 | ) |  | $ | (519 | ) |  | $ | (17,301 | ) |  | $ | — |
Asset Derivatives at September 30, 2012 |
Commodity contracts |  | Fair asset and fair liability value of derivative instruments |  | $ | 15,100 |  |  | $ | 1,749 |  |  | $ | 13,351 |  |  | $ | — |
Commodity contract assets at September 30, 2012 |  | $ | 15,100 |  |  | $ | 1,749 |  |  | $ | 13,351 |  |  | $ | — |
Liability Derivatives at September 30, 2012 |
Commodity contracts |  | Fair liability and fair asset value of derivative instruments |  | $ | (10,549 | ) |  | $ | (1,898 | ) |  | $ | (8,651 | ) |  | $ | — |
Commodity contract liabilities at September 30, 2012 |  | $ | (10,549 | ) |  | $ | (1,898 | ) |  | $ | (8,651 | ) |  | $ | — |

(In thousands) |  |  |  |  |  |  |  |  |  |  |
The Effect of Derivative Instruments on the Statement of Operations |
|  |  |  | Amount of (Gain) or Loss Recognized |
|  |  |  | Years Ended September 30, |
Derivatives Not Designated as Hedging Instruments Under FASB ASC 815-10 |  | Location of (Gain) or Loss Recognized in Income on Derivative |  | 2013 |  |  | 2012 |  |  | 2011 |
Commodity contracts |  | Cost of product (a) |  | $ | 17,769 |  |  | $ | 18,636 |  |  | $ | (9,089 | )
Commodity contracts |  | Cost of installations and service (a) |  | $ | (440 | ) |  | $ | (284 | ) |  | $ | (1,030 | )
Commodity contracts |  | Delivery and branch expenses (a) |  | $ | (286 | ) |  | $ | (82 | ) |  | $ | (740 | )
Commodity contracts |  | (Increase) / decrease in the fair value of derivative instruments |  | $ | 6,775 |  |  | $ | (8,549 | ) |  | $ | 2,567 |

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

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6) 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):

|  | September 30, |
|  | 2013 |  |  | 2012 |
Product |  | $ | 50,197 |  |  | $ | 30,786 |
Parts and equipment |  |  | 17,953 |  |  |  | 16,679 |
Total inventory |  | $ | 68,150 |  |  | $ | 47,465 |

Product inventories were comprised of 17.1 million gallons and 10.0 million gallons on September 30, 2013 and September 30, 2012, respectively. The Partnership has market price based product supply contracts for approximately 221 million gallons of home heating oil and propane, that it expects to fully utilize to meet its requirements over the next twelve months.

During fiscal 2013, Global Companies LLC , JPMorgan Ventures Energy Corporation, NIC Holding Corp. (Northville Industries) and Phillips 66 provided approximately 19%, 11%, 9% and 9% respectively, of our petroleum product purchases. During fiscal 2012, Global Companies LLC provided approximately 24% of our petroleum product purchases. No other single supplier provided more than 10% of our petroleum product supply during fiscal 2012, however, JPMorgan Ventures Energy Corporation and NIC Holding Corp. (Northville Industries) each provided approximately 9%.

7) Property and Equipment

The components of property and equipment and their estimated useful lives were as follows (in thousands):

|  | September 30, |
|  | 2013 |  |  | 2012 |
Land and land improvements |  | $ | 13,958 |  |  | $ | 13,904 |
Buildings and leasehold improvements |  |  | 27,571 |  |  |  | 27,354 |
Fleet and other equipment |  |  | 46,260 |  |  |  | 47,742 |
Tanks and equipment |  |  | 21,445 |  |  |  | 18,792 |
Furniture, fixtures and office equipment |  |  | 61,228 |  |  |  | 59,268 |
Total |  |  | 170,462 |  |  |  | 167,060 |
Less accumulated depreciation |  |  | 119,139 |  |  |  | 114,452 |
Property and equipment, net |  | $ | 51,323 |  |  | $ | 52,608 |

Depreciation expense was $8.1 million, $8.1 million, and $7.3 million, for the fiscal years ended September 30, 2013, 2012, and 2011 respectively.

8) Business Combinations

During fiscal 2013, the Partnership acquired two heating oil dealers for an aggregate purchase price of approximately $1.4 million. The gross purchase price was allocated $1.3 million to intangible assets, $0.2 million to fixed assets and reduced by $0.1 million for working capital credits. The operating results of these two acquisitions have been included in the Partnership’s consolidated financial statements since the date of acquisition, and are not material to the Partnership’s financial condition, results of operations, or cash flows. The fair values of the assets acquired and liabilities assumed are comprised primarily of intangibles and certain working capital items which are reflected in the Consolidated Balance Sheet as of September 30, 2013.

During fiscal 2012, the Partnership acquired seven heating oil and propane dealers for an aggregate purchase price of approximately $39.2 million. The gross purchase price was allocated $32.4 million to intangible assets, $8.0 million to fixed assets and reduced by $1.2 million for working capital credits.

During fiscal 2011, the Partnership acquired four retail heating oil and propane dealers for an aggregate purchase price of approximately $9.7 million. The gross purchase price was allocated $4.3 million to intangible assets, $3.5 million to fixed assets and other long term assets, and working capital of $1.9 million.

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9) Goodwill and Other Intangible Assets

Goodwill

Under FASB ASC 350-10-05 Intangibles-Goodwill and Other, goodwill impairment if any, needs to be determined if the net book value of a reporting unit exceeds its estimated fair value. If goodwill of a reporting unit is determined to be impaired, the amount of impairment is measured based on the excess of the net book value of the goodwill over the implied fair value of the goodwill. The Partnership has selected August 31 of each year to perform its annual impairment review, whereby the total enterprise value as indicated by the Income Approach and Market Approach (consisting of the Market Comparable and Market Transaction Approach) is compared to the Partnership’s book value of net assets and reconciled to the Partnership’s market capitalization.

The Partnership performed its annual goodwill impairment valuation in each of the periods ending August 31, 2013, 2012, and 2011, and it was determined based on each year’s analysis that there was no goodwill impairment.

The preparation of this analysis was based upon management’s estimates and assumptions, and future impairment calculations would be affected by actual results that are materially different from projected amounts. To provide for a sensitivity of the discount rates and transaction multiples used, ranges of high and low values are employed in the analysis, with the low values examined to ensure that a reasonably likely change in an assumption would not cause the Partnership to reach a different conclusion.

A summary of changes in the Partnership’s goodwill during the fiscal years ended September 30, 2013 and 2012 are as follows (in thousands):

Balance as of September 30, 2011 |  | $ | 199,296 |
Fiscal year 2012 business combination |  |  | 1,807 |
Balance as of September 30, 2012 |  |  | 201,103 |
Fiscal year 2013 business combination |  |  | 27 |
Balance as of September 30, 2013 |  | $ | 201,130 |

Intangibles, net

Intangible assets subject to amortization consist of the following (in thousands):

|  | September 30, |
|  | 2013 |  |  | 2012 |
|  | Gross Carrying Amount |  |  | Accum. Amortization |  |  | Net |  |  | Gross Carrying Amount |  |  | Accum. Amortization |  |  | Net |
Customer lists and other intangibles |  | $ | 288,011 |  |  | $ | 221,221 |  |  | $ | 66,790 |  |  | $ | 286,783 |  |  | $ | 212,071 |  |  | $ | 74,712 |

Amortization expense for intangible assets was $9.2 million, $8.2 million, and $10.3 million, for the fiscal years ended September 30, 2013, 2012, and 2011, respectively. Total estimated annual amortization expense related to intangible assets subject to amortization, for the year ended September 30, 2014 and the four succeeding fiscal years ended September 30, is as follows (in thousands):

|  | Amount |
2014 |  | $ | 9,188 |
2015 |  | $ | 9,053 |
2016 |  | $ | 8,882 |
2017 |  | $ | 8,362 |
2018 |  | $ | 7,523 |

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10) Accrued Expenses and Other Current Liabilities

The components of accrued expenses and other current liabilities were as follows (in thousands):

|  | September 30, |
|  | 2013 |  |  | 2012 |
Accrued wages and benefits |  | $ | 18,932 |  |  | $ | 15,578 |
Accrued insurance and environmental costs |  |  | 58,470 |  |  |  | 52,934 |
Other accrued expenses and other current liabilities |  |  | 9,740 |  |  |  | 10,006 |
Total accrued expenses and other current liabilities |  | $ | 87,142 |  |  | $ | 78,518 |

11) Long-Term Debt and Bank Facility Borrowings

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

|  | September 30, |
|  | 2013 |  |  | 2012 |
|  | Carrying Amount |  |  | Fair Value (a) |  |  | Carrying Amount |  |  | Fair Value (a) |
8.875% Senior Notes (b) |  | $ | 124,460 |  |  | $ | 130,000 |  |  | $ | 124,357 |  |  | $ | 126,563 |
Revolving Credit Facility Borrowings (c) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Total debt |  | $ | 124,460 |  |  | $ | 130,000 |  |  | $ | 124,357 |  |  | $ | 126,563 |
Total long-term portion of debt |  | $ | 124,460 |  |  | $ | 130,000 |  |  | $ | 124,357 |  |  | $ | 126,563 |

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

(b) | The 8.875% Senior Notes were originally issued in November 2010 in a private placement offering pursuant to Rule 144A and Regulation S under the Securities Act of 1933, and in February 2011, were exchanged for substantially identical public notes registered with the Securities and Exchange Commission. These public notes mature in December 2017 and accrue interest at an annual rate of 8.875% requiring semi-annual interest payments on June 1 and December 1 of each year. The discount on these notes was $0.5 million at September 30, 2013. Under the terms of the indenture, these notes permit restricted payments after passing certain financial tests. The Partnership can incur debt up to $100 million for acquisitions and can also pay restricted payments of $22.0 million without passing certain financial tests.

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

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

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

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

At September 30, 2013, no amount was outstanding under the revolving credit facility and $44.7 million of letters of credit were issued. At September 30, 2012, no amount was outstanding under the revolving credit facility and $42.8 million of letters of credit were issued.

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

At September 30, 2013, availability was $164.3 million, the restricted net assets totaled approximately $375 million and the Partnership was in compliance with the fixed charge coverage ratio. Restricted net assets are assets in the Partnership’s subsidiaries the distribution or transfer of which to Star Gas Partners, L.P. are subject to limitations under its revolving credit facility. At September 30, 2012, availability was $179.2 million, the restricted net assets totaled approximately $378 million and the Partnership was in compliance with the fixed charge coverage ratio.

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

As of September 30, 2013, the maturities including working capital borrowings during fiscal years ending September 30, are set forth in the following table (in thousands):

2014 |  | $ | — |
2015 |  | $ | — |
2016 |  | $ | — |
2017 |  | $ | — |
2018 |  | $ | 125,000 |
Thereafter |  | $ | — |

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12) Employee Benefit Plans

Defined Contribution Plans

The Partnership has two 401(k) plans that cover eligible non-union and union employees. Subject to IRS limitations, the 401(k) plans provide for each participant to contribute from 0% to 60% of compensation. For most participants, the Partnership generally can make a 4% (to a maximum of 5.5% for participants who had 10 or more years of service at the time the Defined Benefit Plans were frozen and who have reached the age 55) core contribution of a participant’s compensation and generally can match 2/3 of each amount a participant contributes up to a maximum of 2.0% of a participant’s compensation. However, participants at specific operating locations that participate in these plans are only eligible for an employer discretionary pretax matching contribution and/or an annual employer discretionary profit sharing contribution. The Partnership’s aggregate contributions to the 401(k) plans during fiscal 2013, 2012, and 2011, were $4.9 million, $4.5 million, and $4.7 million, respectively.

Management Incentive Compensation Plan

The Partnership has a Management Incentive Compensation Plan. The long-term compensation structure is intended to align the employee’s performance with the long-term performance of our unitholders. Under the Plan, employees who participate shall be entitled to receive a pro rata share of an amount in cash equal to:

| • |  | 50% of the distributions (“Incentive Distributions”) of Available Cash in excess of the minimum quarterly distribution of $0.0675 per unit otherwise distributable to Kestrel Heat pursuant to the Partnership Agreement on account of its general partner units; and

| • |  | 50% of the cash proceeds (the “Gains Interest”) which Kestrel Heat shall receive from the sale of its general partner units (as defined in the Partnership Agreement), less expenses and applicable taxes.

The pro rata share payable to each participant under the Plan is based on the number of participation points as described under “Fiscal 2013 Compensation Decisions—Management Incentive Compensation Plan.” The amount paid in Incentive Distributions is governed by the Partnership Agreement and the calculation of Available Cash.

To fund the benefits under the Plan, Kestrel Heat has agreed to forego receipt of the amount of Incentive Distributions that are payable to plan participants. For accounting purposes, amounts payable to management under this Plan will be treated as compensation and will reduce net income. Kestrel Heat has also agreed to contribute to the Partnership, as a contribution to capital, an amount equal to the Gains Interest payable to participants in the Plan by the Partnership. The Partnership is not required to reimburse Kestrel Heat for amounts payable pursuant to the Plan.

The Plan is administered by the Partnership’s Chief Financial Officer under the direction of the Board or by such other officer as the Board may from time to time direct. Determination of the employees that participate in the Plan is under the sole discretion of the Board of Directors. In general, no payments will be made under this plan if the Partnership is not distributing cash under the Incentive Distributions described above.

The Board of Directors reserves the right to amend, change or terminate the Plan at any time. Without limiting the foregoing, the Board of Directors reserves the right to adjust the amount of Incentive Distributions to be allocated to the Bonus Pool if in its judgment extenuating circumstances warrant adjustment from the guidelines, and to change the timing of any payments due thereunder at any time in its sole discretion.

The Partnership distributed to management and the general partner Incentive Distributions of approximately $330,000 during fiscal 2013, $277,000 during fiscal 2012, and $261,000 during fiscal 2011. Included in these amounts for fiscal 2013, 2012, and 2011, were distributions under the management incentive compensation plan of $165,000, $138,000 and $130,000, respectively, of which named executive officers received approximately $119,000 during fiscal 2013, $99,000 during fiscal 2012, and $92,000 during fiscal 2011. With regard to the Gains Interest, Kestrel Heat has not given any indication that it will sell its general partner units within the next twelve months. Thus the Plan’s value attributable to the Gains Interest currently cannot be determined.

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Multiemployer Pension Plans

We contribute to various multiemployer union administered pension plans under the terms of collective bargaining agreements that provide for such plans for covered union-represented employees. The risks of participating in these multiemployer plans are different from single-employer plans in that assets contributed are pooled and may be used to provide benefits to employees of other participating employers. If a participating employer stops contributing to the plan, the remaining participating employers may be required to bear the unfunded obligations of the plan. If we choose to stop participating in a multiemployer plan, we may be required to pay a withdrawal liability based on the underfunded status of the plan. However, cessation of participation in a multiemployer plan and subsequent payment of any withdrawal liability is subject to the collective bargaining process.

The following table outlines our participation and contributions to multiemployer pension plans for the periods ended September 30, 2013, 2012 and 2011. The EIN/Pension Plan Number column provides the Employer Identification Number (“EIN”) and the three-digit plan number. The most recent Pension Protection Act Zone Status for 2013 and 2012 relates to the plans’ two most recent fiscal year-ends, based on information received from the plans and are certified by the plans’ actuary. Among other factors, plans in the red zone are generally less than 65 percent funded, plans in the yellow zone are less than 80 percent funded, and plans in the green zone are at least 80 percent funded. The FIP/RP Status Pending/Implemented column indicates plans for which a financial improvement plan (“FIP”) or a rehabilitation plan (“RP”) is either pending or has been implemented. Certain plans have been aggregated in the All Other Multiemployer Pension Plans line of the following table, as our participation in each of these individual plans are not significant.

For the Westchester Teamsters Pension Fund, Local 553 Pension Fund and Local 463 Pension Fund, we provided more than 5 percent of the total plan contributions from all employers for 2013, 2012 and 2011, as disclosed in the respective plan’s Form 5500. The collective bargaining agreements of these plans require contributions based on the hours worked and there are no minimum contributions required.

|  |  |  | Pension Protection Act Zone Status |  | FIP / RP Status |  | Partnership Contributions (in thousands) |  |  |  |  |  |
Pension Fund |  | EIN / Pension Plan Number |  | 2013 |  | 2012 |  | Pending / Implemented |  | 2013 |  |  | 2012 |  |  | 2011 |  |  | Surcharge Imposed |  | Expiration Date of Collective- Bargaining Agreement |
New England Teamsters & Trucking Industry Pension Fund |  | 04-6372430 / 001 |  | Yellow |  | Yellow |  | N/A |  | $ | 2,709 |  |  | $ | 2,532 |  |  | $ | 2,512 |  |  | No |  |  | 3/31/2014 |
Westchester Teamsters Pension Fund |  | 13-6123973 / 001 |  | Green |  | Green |  | N/A |  |  | 820 |  |  |  | 771 |  |  |  | 817 |  |  | No |  |  | 1/31/2014 |
Local 553 Pension Fund |  | 13-6637826 / 001 |  | Green |  | Green |  | N/A |  |  | 2,729 |  |  |  | 2,152 |  |  |  | 2,082 |  |  | No |  |  | 1/15/2014 |
Local 463 Pension Fund |  | 11-1800729 / 001 |  | Green |  | Green |  | N/A |  |  | 146 |  |  |  | 155 |  |  |  | 155 |  |  | No |  |  | 2/28/2014 |
All Other Multiemployer Pension Plans |  |  |  |  |  |  |  |  |  |  | 1,614 |  |  |  | 1,627 |  |  |  | 1,364 |  |  |  |  |  |  |
|  |  |  |  |  |  |  | Total Contributions |  | $ | 8,018 |  |  | $ | 7,237 |  |  | $ | 6,930 |  |  |  |  |  |  |

Defined Benefit Plans

The Partnership accounts for its two frozen defined benefit pension plans (“the Plan”) in accordance with FASB ASC 715-10-05 Compensation-Retirement Benefits. The Partnership has no post-retirement benefit plans.

The following table provides the net periodic benefit cost for the period, a reconciliation of the changes in the Plan assets, projected benefit obligations, and the amounts recognized in other comprehensive income and accumulated other comprehensive income at the dates indicated using a measurement date of September 30 (in thousands):

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##### Table of Contents

Debit / (Credit) |  | Net Periodic Pension Cost in Income Statement |  |  | Cash |  |  | Fair Value of Pension Plan Assets |  |  | Projected Benefit Obligation |  |  | Other Comprehensive (Income) / Loss |  |  | Gross Pension Related Accumulated Other Comprehensive Income |
Fiscal Year 2011 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Beginning balance |  |  |  |  |  |  |  |  |  | $ | 49,323 |  |  | $ | (65,922 | ) |  |  |  |  |  | $ | 33,212 |
Interest cost |  |  | 2,993 |  |  |  |  |  |  |  |  |  |  |  | (2,993 | ) |  |  |  |  |  |  |  |
Actual return on plan assets |  |  | (3,984 | ) |  |  |  |  |  |  | 3,984 |  |  |  |  |  |  |  |  |  |  |  |  |
Employer contributions |  |  |  |  |  |  | (3,224 | ) |  |  | 3,224 |  |  |  |  |  |  |  |  |  |  |  |  |
Benefit payments |  |  |  |  |  |  |  |  |  |  | (4,097 | ) |  |  | 4,097 |  |  |  |  |  |  |  |  |
Investment and other expenses |  |  | (377 | ) |  |  |  |  |  |  |  |  |  |  | 377 |  |  |  |  |  |  |  |  |
Difference between actual and expected return on plan assets |  |  | 597 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (597 | ) |  |  |  |
Anticipated expenses |  |  | 246 |  |  |  |  |  |  |  |  |  |  |  | (246 | ) |  |  |  |  |  |  |  |
Actuarial loss |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (3,191 | ) |  |  | 3,191 |  |  |  |  |
Amortization of unrecognized net actuarial loss |  |  | 2,765 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (2,765 | ) |  |  |  |
Annual cost/change |  | $ | 2,240 |  |  | $ | (3,224 | ) |  |  | 3,111 |  |  |  | (1,956 | ) |  | $ | (171 | ) |  |  | (171 | )
Ending balance |  |  |  |  |  |  |  |  |  | $ | 52,434 |  |  | $ | (67,878 | ) |  |  |  |  |  | $ | 33,041 |
Funded status at the end of the year |  |  |  |  |  |  |  |  |  |  |  |  |  | $ | (15,444 | ) |  |  |  |  |  |  |  |
Fiscal Year 2012 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Interest cost |  |  | 2,858 |  |  |  |  |  |  |  |  |  |  |  | (2,858 | ) |  |  |  |  |  |  |  |
Actual return on plan assets |  |  | (8,727 | ) |  |  |  |  |  |  | 8,727 |  |  |  |  |  |  |  |  |  |  |  |  |
Employer contributions |  |  |  |  |  |  | (3,365 | ) |  |  | 3,365 |  |  |  |  |  |  |  |  |  |  |  |  |
Benefit payments |  |  |  |  |  |  |  |  |  |  | (4,223 | ) |  |  | 4,223 |  |  |  |  |  |  |  |  |
Investment and other expenses |  |  | (374 | ) |  |  |  |  |  |  |  |  |  |  | 374 |  |  |  |  |  |  |  |  |
Difference between actual and expected return on plan assets |  |  | 5,075 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (5,075 | ) |  |  |  |
Anticipated expenses |  |  | 262 |  |  |  |  |  |  |  |  |  |  |  | (262 | ) |  |  |  |  |  |  |  |
Actuarial loss |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (6,650 | ) |  |  | 6,650 |  |  |  |  |
Amortization of unrecognized net actuarial loss |  |  | 2,751 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (2,751 | ) |  |  |  |
Annual cost/change |  | $ | 1,845 |  |  | $ | (3,365 | ) |  |  | 7,869 |  |  |  | (5,173 | ) |  | $ | (1,176 | ) |  |  | (1,176 | )
Ending balance |  |  |  |  |  |  |  |  |  | $ | 60,303 |  |  | $ | (73,051 | ) |  |  |  |  |  | $ | 31,865 |
Funded status at the end of the year |  |  |  |  |  |  |  |  |  |  |  |  |  | $ | (12,748 | ) |  |  |  |  |  |  |  |
Fiscal Year 2013 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Interest cost |  |  | 2,477 |  |  |  |  |  |  |  |  |  |  |  | (2,477 | ) |  |  |  |  |  |  |  |
Actual return on plan assets |  |  | (332 | ) |  |  |  |  |  |  | 332 |  |  |  |  |  |  |  |  |  |  |  |  |
Employer contributions |  |  |  |  |  |  | (3,476 | ) |  |  | 3,476 |  |  |  |  |  |  |  |  |  |  |  |  |
Benefit payments |  |  |  |  |  |  |  |  |  |  | (4,083 | ) |  |  | 4,083 |  |  |  |  |  |  |  |  |
Investment and other expenses |  |  | (285 | ) |  |  |  |  |  |  |  |  |  |  | 285 |  |  |  |  |  |  |  |  |
Difference between actual and expected return on plan assets |  |  | (3,475 | ) |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 3,475 |  |  |  |  |
Anticipated expenses |  |  | 302 |  |  |  |  |  |  |  |  |  |  |  | (302 | ) |  |  |  |  |  |  |  |
Actuarial gain |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 7,157 |  |  |  | (7,157 | ) |  |  |  |
Amortization of unrecognized net actuarial loss |  |  | 2,655 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (2,655 | ) |  |  |  |
Annual cost/change |  | $ | 1,342 |  |  | $ | (3,476 | ) |  |  | (275 | ) |  |  | 8,746 |  |  | $ | (6,337 | ) |  |  | (6,337 | )
Ending balance |  |  |  |  |  |  |  |  |  | $ | 60,028 |  |  | $ | (64,305 | ) |  |  |  |  |  | $ | 25,528 |
Funded status at the end of the year |  |  |  |  |  |  |  |  |  |  |  |  |  | $ | (4,277 | ) |  |  |  |  |  |  |  |

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##### Table of Contents

At September 30, 2013 and 2012, the amounts included on the balance sheet in other long-term liabilities were $4.3 million and $12.7 million, respectively.

The $25.5 million net actuarial loss balance at September 30, 2013 for the two frozen defined benefit pension plans in accumulated other comprehensive income will be recognized and amortized into net periodic pension costs as an actuarial loss in future years. The estimated amount that will be amortized from accumulated other comprehensive income into net periodic pension cost over the next fiscal year is $2.1 million.

|  | September 30, |
Weighted-Average Assumptions Used in the Measurement of the Partnership’s Benefit Obligation |  | 2013 |  |  | 2012 |  |  | 2011 |
Discount rate at year end date |  |  | 4.45 | % |  |  | 3.50 | % |  |  | 4.35 | %
Expected return on plan assets for the year ended |  |  | 7.00 | % |  |  | 7.75 | % |  |  | 7.75 | %
Rate of compensation increase |  |  | N/A |  |  |  | N/A |  |  |  | N/A |

The expected return on plan assets is determined based on the expected long-term rate of return on plan assets and the market-related value of plan assets determined using fair value.

The Partnership’s expected long-term rate of return on plan assets is updated at least annually, taking into consideration our asset allocation, historical returns on the types of assets held, and the current economic environment. The Partnership revised its return on plan assets assumption to 5.75% per annum effective fiscal year 2014.

The discount rate used to determine net periodic pension expense for fiscal year 2013, 2012 and 2011 was 3.50%, 4.35%, and 4.70% respectively. The discount rate used by the Partnership in determining pension expense and pension obligations reflects the yield of high quality (AA or better rating by a recognized rating agency) corporate bonds whose cash flows are expected to match the timing and amounts of projected future benefit payments.

The Plan’s objectives are to have the ability to pay benefit and expense obligations when due, to maintain the funded ratio of the Plan, to maximize return within reasonable and prudent levels of risk in order to minimize contributions and charges to the profit and loss statement, and to control costs of administering the Plan and managing the investments of the Plan. The strategic asset allocation of the Plan (currently 80% domestic fixed income, 15% domestic equities and 5% international equities) is based on a long-term perspective, and as the Plan gets closer to being fully funded, the allocations have been adjusted to lower volatility from equity holdings.

The fair values and percentage of the Partnership’s pension plan assets by asset category are as follows (in thousands):

Asset Category at September 30, 2013 |  | Level 1 |  |  | Level 2 |  |  | Level 3 |  |  | Total |  |  | Concentration Percentage |
Corporate and U.S. government bond fund (1) |  |  | 47,364 |  |  |  | — |  |  |  | — |  |  |  | 47,364 |  |  |  | 79 | %
U.S. large-cap equity (1) |  |  | 9,123 |  |  |  | — |  |  |  | — |  |  |  | 9,123 |  |  |  | 15 | %
International equity (1) |  |  | 3,082 |  |  |  | — |  |  |  | — |  |  |  | 3,082 |  |  |  | 5 | %
Cash |  |  | 459 |  |  |  | — |  |  |  | — |  |  |  | 459 |  |  |  | 1 | %
Total |  |  | 60,028 |  |  |  | — |  |  |  | — |  |  |  | 60,028 |  |  |  | 100 | %

(1) | Represent investments in Vanguard funds that seek to replicate the asset category description.

The Partnership expects to make pension contributions of approximately $2.7 million in fiscal 2014.

Expected benefit payments over each of the next five years will total approximately $4.4 million per year. Expected benefit payments for the five years thereafter will aggregate approximately $21.2 million.

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##### Table of Contents

13) Income Taxes

Income tax expense is comprised of the following for the indicated periods (in thousands):

|  | Years Ended September 30, |
|  | 2013 |  |  | 2012 |  |  | 2011 |
Current: |  |  |  |  |  |  |  |  |  |  |  |
Federal |  | $ | 14,486 |  |  | $ | 2,168 |  |  | $ | 3,216 |
State |  |  | 3,759 |  |  |  | 1,495 |  |  |  | 3,676 |
Deferred |  |  | 1,676 |  |  |  | 12,913 |  |  |  | 15,831 |
|  | $ | 19,921 |  |  | $ | 16,576 |  |  | $ | 22,723 |

The provision for income taxes differs from income taxes computed at the Federal statutory rate as a result of the following (in thousands):

|  | Years Ended September 30, |
|  | 2013 |  |  | 2012 |  |  | 2011 |
Income from continuing operations before taxes |  | $ | 49,827 |  |  | $ | 42,565 |  |  | $ | 47,067 |
Provision for income taxes: |  |  |  |  |  |  |  |  |  |  |  |
Tax at Federal statutory rate |  | $ | 17,440 |  |  | $ | 14,898 |  |  | $ | 16,473 |
Impact of Partnership income or loss not subject to federal income taxes |  |  | 97 |  |  |  | 697 |  |  |  | 1,631 |
State taxes net of federal benefit |  |  | 3,192 |  |  |  | 2,801 |  |  |  | 3,493 |
Permanent differences |  |  | 37 |  |  |  | 28 |  |  |  | 54 |
Change in valuation allowance |  |  | (658 | ) |  |  | (14 | ) |  |  | 672 |
Change in unrecognized tax benefit |  |  | 55 |  |  |  | (1,669 | ) |  |  | 189 |
Other |  |  | (242 | ) |  |  | (165 | ) |  |  | 211 |
|  | $ | 19,921 |  |  | $ | 16,576 |  |  | $ | 22,723 |

The components of the net deferred taxes and the related valuation allowance for the years ended September 30, 2013 and September 30, 2012 using current tax rates are as follows (in thousands):

|  | September 30, |
|  | 2013 |  |  | 2012 |
Deferred tax assets: |  |  |  |  |  |  |  |
Net operating loss carryforwards |  | $ | 6,760 |  |  | $ | 8,626 |
Vacation accrual |  |  | 2,580 |  |  |  | 2,586 |
Pension accrual |  |  | 2,672 |  |  |  | 5,201 |
Allowance for bad debts |  |  | 3,158 |  |  |  | 2,845 |
Fair value of derivative instruments |  |  | 2,314 |  |  |  | — |
Insurance accrual |  |  | 21,073 |  |  |  | 18,085 |
Inventory |  |  | 941 |  |  |  | 869 |
Alternative minimum tax credit carryforward |  |  | 261 |  |  |  | 261 |
Other, net |  |  | 1,906 |  |  |  | 2,188 |
Total deferred tax assets |  |  | 41,665 |  |  |  | 40,661 |
Valuation allowance |  |  | — |  |  |  | (658 | )
Net deferred tax assets |  | $ | 41,665 |  |  | $ | 40,003 |
Deferred tax liabilities: |  |  |  |
Property and equipment |  | $ | 2,225 |  |  | $ | 1,947 |
Intangibles |  |  | 26,285 |  |  |  | 20,164 |
Fair value of derivative instruments |  |  | — |  |  |  | 484 |
Total deferred tax liabilities |  | $ | 28,510 |  |  | $ | 22,595 |
Net deferred taxes |  | $ | 13,155 |  |  | $ | 17,408 |

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##### Table of Contents

As of the calendar tax year ended December 31, 2012, Star Acquisitions, a wholly-owned subsidiary of the Partnership, had a Federal net operating loss carry forward (“NOLs”) of approximately $10.6 million. The Federal NOLs, which will expire between 2018 and 2024, are generally available to offset any future taxable income but are also subject to annual limitations of between $1.0 million and $2.2 million.

FASB ASC 740-10-05-6 Income Taxes, Uncertain Tax Position, provides financial statement accounting guidance for uncertainty in income taxes and tax positions taken or expected to be taken in a tax return. At September 30, 2013, we had unrecognized income tax benefits totaling $0.8 million including related accrued interest and penalties of $0.1 million. These unrecognized tax benefits are primarily the result of State tax uncertainties. If recognized, these tax benefits would be recorded as a benefit to the effective tax rate.

Tax Uncertainties (in thousands)

Balance at September 30, 2012 |  | $ | 700 |
Additions based on tax positions related to the current year |  |  | — |
Additions for tax positions of prior years |  |  | 84 |
Reduction for tax positions of prior years |  |  | — |
Reductions due to lapse in statue of limitations/settlements |  |  | — |
Balance at September 30, 2013 |  | $ | 784 |

We believe that the total liability for unrecognized tax benefits will not materially change during the next 12 months ending September 30, 2014. 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.

14) Lease Commitments

The Partnership has entered into certain operating leases for office space, trucks and other equipment. The future minimum rental commitments at September 30, 2013 under operating leases having an initial or remaining non-cancelable term of one year or more are as follows (in thousands):

2014 |  | $ | 13,819 |
2015 |  |  | 12,130 |
2016 |  |  | 9,892 |
2017 |  |  | 6,952 |
2018 |  |  | 3,721 |
Thereafter |  |  | 6,919 |
Total future minimum lease payments |  | $ | 53,433 |

Rent expense for the fiscal years ended September 30, 2013, 2012, and 2011, was $14.7 million, $14.2 million, and $13.8 million, respectively.

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##### Table of Contents

15) Supplemental Disclosure of Cash Flow Information

|  | Years Ended September 30, |
(in thousands) |  | 2013 |  |  | 2012 |  |  | 2011 |
Cash paid during the period for: |  |  |  |  |  |  |  |  |  |  |  |
Income taxes, net |  | $ | 16,137 |  |  | $ | 6,175 |  |  | $ | 9,215 |
Interest |  | $ | 14,376 |  |  | $ | 14,487 |  |  | $ | 12,994 |
Debt redemption premium |  | $ | — |  |  | $ | — |  |  | $ | 1,409 |
Non-cash financing activities: |  |  |  |  |  |  |  |  |  |  |  |
Increase (decrease) in interest expense—amortization of debt discount 8.875% and debt premium 10.25% |  | $ | 103 |  |  | $ | 94 |  |  | $ | 52 |
Decrease in net debt premium attributable to redemption of debt |  | $ | — |  |  | $ | — |  |  | $ | 247 |

16) Commitments and Contingencies

The Partnership’s operations are subject to all operating hazards and risks normally incidental to handling, storing and transporting and otherwise providing for use by consumers of combustible liquids such as home heating oil and propane. As a result, at any given time the Partnership is a defendant in various legal proceedings and litigation arising in the ordinary course of business. 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 for personal and property damage or that these levels of insurance will be available in the future at economical prices. 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.

17) Earnings Per Limited Partner Units

The following table presents the net income allocation and per unit data in accordance with FASB ASC 260-10-45-60 Earnings per Share, Master Limited Partnerships (EITF 03-06):

Basic and Diluted Earnings Per Limited Partner: |  | Years Ended September 30, |
(in thousands, except per unit data) |  | 2013 |  |  | 2012 |  |  | 2011 |
Net income |  | $ | 29,906 |  |  | $ | 25,989 |  |  | $ | 24,344 |
Less General Partners’ interest in net income |  |  | 159 |  |  |  | 136 |  |  |  | 115 |
Net income available to limited partners |  |  | 29,747 |  |  |  | 25,853 |  |  |  | 24,229 |
Less dilutive impact of theoretical distribution of earnings under FASB ASC 260-10-45-60 * |  |  | 2,010 |  |  |  | 1,142 |  |  |  | 574 |
Limited Partner’s interest in net income under FASB ASC 260-10-45-60 |  | $ | 27,737 |  |  | $ | 24,711 |  |  | $ | 23,655 |
Per unit data: |  |  |  |  |  |  |  |  |  |  |  |
Basic and diluted net income available to limited partners |  | $ | 0.50 |  |  | $ | 0.42 |  |  | $ | 0.36 |
Less dilutive impact of theoretical distribution of earnings under FASB ASC 260-10-45-60 * |  |  | 0.03 |  |  |  | 0.02 |  |  |  | 0.01 |
Limited Partner’s interest in net income under FASB ASC 260-10-45-60 |  | $ | 0.47 |  |  | $ | 0.40 |  |  | $ | 0.35 |
Weighted average number of Limited Partner units outstanding |  |  | 59,409 |  |  |  | 61,931 |  |  |  | 66,822 |

* | In any accounting period where the Partnership’s aggregate net income exceeds its aggregate distribution for such period, the Partnership is required as per FASB ASC 260-10-45-60 to present net income per limited partner unit as if all of the earnings for the period were distributed, based on the contractual participation rights of the security to share in earnings, 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.

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##### Table of Contents

18) Selected Quarterly Financial Data (unaudited)

Due to the seasonal nature of the Partnership’s business, we generally realize net income during the quarters ending December and March and net losses during the quarters ending June and September.

|  | Three Months Ended |  |  |  |
(in thousands - except per unit data) |  | Dec. 31, 2012 |  |  | Mar. 31, 2013 |  |  | Jun. 30, 2013 |  |  | Sep. 30, 2013 |  |  | Total |
Sales |  | $ | 516,525 |  |  | $ | 785,139 |  |  | $ | 262,524 |  |  | $ | 177,608 |  |  | $ | 1,741,796 |
Gross profit for product, installation and service |  |  | 102,691 |  |  |  | 162,011 |  |  |  | 54,907 |  |  |  | 33,519 |  |  |  | 353,128 |
Operating income (loss) |  |  | 18,577 |  |  |  | 75,229 |  |  |  | (8,001 | ) |  |  | (19,800 | ) |  |  | 66,005 |
Income (loss) before income taxes |  |  | 14,669 |  |  |  | 70,796 |  |  |  | (11,952 | ) |  |  | (23,686 | ) |  |  | 49,827 |
Net income (loss) |  |  | 9,752 |  |  |  | 41,679 |  |  |  | (7,588 | ) |  |  | (13,937 | ) |  |  | 29,906 |
Limited Partner interest in net income (loss) |  |  | 9,699 |  |  |  | 41,454 |  |  |  | (7,547 | ) |  |  | (13,859 | ) |  |  | 29,747 |
Net income (loss) per Limited Partner unit: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Basic and diluted (a) |  | $ | 0.15 |  |  | $ | 0.58 |  |  | $ | (0.13 | ) |  | $ | (0.24 | ) |  | $ | 0.47 |
|  | Three Months Ended |  |  |  |
(in thousands - except per unit data) |  | Dec. 31, 2011 |  |  | Mar. 31, 2012 |  |  | Jun. 30, 2012 |  |  | Sep. 30, 2012 |  |  | Total |
Sales |  | $ | 461,474 |  |  | $ | 629,592 |  |  | $ | 232,476 |  |  | $ | 174,046 |  |  | $ | 1,497,588 |
Gross profit for product, installation and service |  |  | 92,450 |  |  |  | 125,994 |  |  |  | 46,550 |  |  |  | 32,783 |  |  |  | 297,777 |
Operating income (loss) |  |  | 9,293 |  |  |  | 74,077 |  |  |  | (18,525 | ) |  |  | (6,586 | ) |  |  | 58,259 |
Income (loss) before income taxes |  |  | 5,583 |  |  |  | 69,873 |  |  |  | (22,434 | ) |  |  | (10,457 | ) |  |  | 42,565 |
Net income (loss) |  |  | 2,931 |  |  |  | 40,482 |  |  |  | (11,789 | ) |  |  | (5,635 | ) |  |  | 25,989 |
Limited Partner interest in net income (loss) |  |  | 2,916 |  |  |  | 40,269 |  |  |  | (11,727 | ) |  |  | (5,605 | ) |  |  | 25,853 |
Net income (loss) per Limited Partner unit: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Basic and diluted (a) |  | $ | 0.05 |  |  | $ | 0.55 |  |  | $ | (0.19 | ) |  | $ | (0.09 | ) |  | $ | 0.40 |

19) Subsequent Events

Quarterly Distribution Declared

On October 29, 2013, we declared a quarterly distribution of $0.0825 per unit, or $0.33 per unit on an annualized basis, on all common units in respect of the fourth quarter of fiscal 2013 payable on November 14, 2013 to holders of record on November 12, 2013. In accordance with our Partnership Agreement, the amount of distributions in excess of the minimum quarterly distribution of $0.0675, are distributed 90% to the holders of common units and 10% to the holders of the general partner units (until certain distribution levels are met), subject to the management incentive compensation plan. As a result, $4.7 million will be paid to the common unit holders, $0.07 million to the general partner (including $0.05 million of incentive distributions) and $0.05 million to management pursuant to the management incentive compensation plan which provides for certain members of management to receive incentive distributions that would otherwise be payable to the general partner.

Common Units Repurchased and Retired

In accordance with the Plan III common unit repurchase program, during the first two months of fiscal 2014 the Partnership repurchased and retired 250 thousand common units at an average price paid of $5.20 per unit.

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Schedule I

STAR GAS PARTNERS, L.P. (PARENT COMPANY)

CONDENSED FINANCIAL INFORMATION OF REGISTRANT

|  | September 30, |
(in thousands) |  | 2013 |  |  | 2012 |
Balance Sheets |  |  |  |  |  |  |  |
ASSETS |  |  |  |  |  |  |  |
Current assets |  |  |  |  |  |  |  |
Cash and cash equivalents |  | $ | 324 |  |  | $ | 317 |
Prepaid expenses and other current assets |  |  | 206 |  |  |  | 268 |
Total current assets |  |  | 530 |  |  |  | 585 |
Investment in subsidiaries (a) |  |  | 384,783 |  |  |  | 387,799 |
Deferred charges and other assets, net |  |  | 2,523 |  |  |  | 2,997 |
Total Assets |  | $ | 387,836 |  |  | $ | 391,381 |
LIABILITIES AND PARTNERS’ CAPITAL |  |  |  |  |  |  |  |
Current liabilities |  |  |  |  |  |  |  |
Accrued expenses |  | $ | 4,095 |  |  | $ | 4,706 |
Total current liabilities |  |  | 4,095 |  |  |  | 4,706 |
Long-term debt (b) |  |  | 124,460 |  |  |  | 124,357 |
Other long-term liabilities |  |  | — |  |  |  | 2,173 |
Partners’ capital |  |  | 259,281 |  |  |  | 260,145 |
Total Liabilities and Partners’ Capital |  | $ | 387,836 |  |  | $ | 391,381 |

(a) | Investments in Star Acquisitions, Inc. and subsidiaries are recorded in accordance with the equity method of accounting.

(b) | Scheduled principal repayments of long-term debt during each of the next five fiscal years ending September 30, are as follows: 2014—$0; 2015—$0; 2016—$0; 2017—$0; 2018—$125,000; thereafter —$0. The $125,000 8.875% Senior Notes mature in December 2017.

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##### Table of Contents

Schedule I

STAR GAS PARTNERS, L.P. (PARENT COMPANY)

CONDENSED FINANCIAL INFORMATION OF REGISTRANT

|  | Years Ended September 30, |
(in thousands) |  | 2013 |  |  | 2012 |  |  | 2011 |
Statements of Operations |  |  |  |  |  |  |  |  |  |  |  |
Revenues |  | $ | — |  |  | $ | — |  |  | $ | — |
General and administrative expenses |  |  | 31 |  |  |  | 2,019 |  |  |  | 2,026 |
Operating loss |  |  | (31 | ) |  |  | (2,019 | ) |  |  | (2,026 | )
Net interest expense |  |  | (11,197 | ) |  |  | (11,188 | ) |  |  | (11,638 | )
Amortization of debt issuance costs |  |  | (474 | ) |  |  | (330 | ) |  |  | (501 | )
Gain (loss) on redemption of debt |  |  | — |  |  |  | — |  |  |  | (1,700 | )
Net loss before equity income |  |  | (11,702 | ) |  |  | (13,537 | ) |  |  | (15,865 | )
Equity income of Star Petro Inc. and subs |  |  | 41,608 |  |  |  | 39,526 |  |  |  | 40,209 |
Net income |  | $ | 29,906 |  |  | $ | 25,989 |  |  | $ | 24,344 |

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##### Table of Contents

Schedule I

STAR GAS PARTNERS, L.P. (PARENT COMPANY)

CONDENSED FINANCIAL INFORMATION OF REGISTRANT

|  | Years Ended September 30, |
(in thousands) |  | 2013 |  |  | 2012 |  |  | 2011 |
Statements of Cash Flows |  |  |  |  |  |  |  |  |  |  |  |
Cash flows provided by (used in) operating activities: |  |  |  |  |  |  |  |  |  |  |  |
Net cash provided by (used in) operating activities (a) |  | $ | 34,537 |  |  | $ | 39,196 |  |  | $ | (4,813 | )
Cash flows provided by (used in) investing activities: |  |  |  |  |  |  |  |  |  |  |  |
Net cash provided by (used in) investing activities |  |  | — |  |  |  | — |  |  |  | — |
Cash flows provided by (used in) financing activities: |  |  |  |  |  |  |  |  |  |  |  |
Repayment of debt |  |  | — |  |  |  | — |  |  |  | (82,499 | )
Proceeds from the issuance of debt |  |  | — |  |  |  | — |  |  |  | 124,188 |
Debt extinguishment costs |  |  | — |  |  |  | — |  |  |  | (1,409 | )
Distributions |  |  | (19,313 | ) |  |  | (19,525 | ) |  |  | (20,677 | )
Unit repurchase |  |  | (15,217 | ) |  |  | (19,648 | ) |  |  | (10,949 | )
Increase in deferred charges |  |  | — |  |  |  | — |  |  |  | (3,777 | )
Net cash provided by (used in) financing activities |  |  | (34,530 | ) |  |  | (39,173 | ) |  |  | 4,877 |
Net increase in cash |  |  | 7 |  |  |  | 23 |  |  |  | 64 |
Cash and cash equivalents at beginning of period |  |  | 317 |  |  |  | 294 |  |  |  | 230 |
Cash and cash equivalents at end of period |  | $ | 324 |  |  | $ | 317 |  |  | $ | 294 |
(a) Includes distributions from subsidiaries |  | $ | 34,530 |  |  | $ | 39,173 |  |  | $ | 32,579 |

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STAR GAS PARTNERS, L.P. AND SUBSIDIARIES

Schedule II

VALUATION AND QUALIFYING ACCOUNTS

Years Ended September 30, 2013, 2012 and 2011

(in thousands)

Year |  | Description |  | Balance at Beginning of Year |  |  | Charged to Costs & Expenses |  |  | Other Changes Add (Deduct) |  |  | Balance at End of Year |
2013 |  | Allowance for doubtful accounts |  | $ | 6,886 |  |  | $ | 6,481 |  |  | $ | (5,439 | ) (a) |  | $ | 7,928 |
2012 |  | Allowance for doubtful accounts |  | $ | 9,530 |  |  | $ | 6,017 |  |  | $ | (8,661 | ) (a) |  | $ | 6,886 |
2011 |  | Allowance for doubtful accounts |  | $ | 5,443 |  |  | $ | 10,388 |  |  | $ | (6,301 | ) (a) |  | $ | 9,530 |

(a) | Bad debts written off (net of recoveries).

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